2. Description of short-listed technologies
The following section provides an overview of each of the short-listed CO2 reuse technologies. The overview includes a general description and the status of the technology, the required CO2 source and the degree of CO2 utilisation. It also identifies the proponents currently involved, the end products, any funding support provided and general barriers and benefits of the reuse technology.
Further detailed information of each CO2 reuse technology can be found in Appendices A to J (as indicated below):
- CO2 for use in enhanced oil Appendix A. (EOR) –
- CO2 as Appendix B. for –
- CO2 as a working fluid for Appendix C. –
- CO2 as feedstock for polymer processing – Appendix D.
- CO2 for use in Appendix E. cultivation –
- CO2 as feedstock for Appendix F. –
- CO2 for use in Appendix G. –
- CO2 for use in bauxite residue carbonation – Appendix H.
- CO2 as feedstock for liquid fuel production – Appendix I.
- CO2 for use in enhanced coal bed methane recovery – Appendix J.
A list of demonstration projects and R&D studies for emerging CO2 reuse technologies are located in Appendix L. This list is based on a desktop study only and is by no means exhaustive.
Enhanced oil recovery (EOR) is the method by which depleted oil fields are injected with compressed CO2, to extract reserves which are otherwise inaccessible. CO2-EOR was first deployed in the 1970’s and is considered a commercially mature technology. Generally EOR relies on the solvent properties of CO2 to dissolve in and decrease the viscosity of the oil (miscible CO2 flooding) as shown in Figure 2.1 below. However, immiscible CO2 flooding may be utilised for heavy crude oil, with the mechanism for oil recovery more associated with gravity displacement.
Figure 2.1 Enhanced oil recovery overview
Table 2.1 Enhanced oil recovery summary
|Technology||Enhanced oil recovery|
|Proponents||Oil companies have pioneered EOR in the USA using CO2 from naturally occurring CO2 reservoirs. Additional anthropogenic CO2 supply for EOR is available from companies employing capture on an industrial plant (e.g. syngas, natural gas sweetening, coal power, fertiliser, or cement production) with access to transport infrastructure within range of suitable oil fields. Existing demonstration size or greater EOR projects, include:Andarko Petroleum Corporation (Salt Creek, USA),(Rangely-Webber EOR, USA), Chinese Government (Daqing EOR, China), EnCana (Weyburn, Canada), Penn West Energy Trust (Pembina Cardium EOR, USA)|
|Description||CO2 is injected into oilto enable recovery of additional oil not recovered by primary production or water flooding. The CO2 acts as solvent, decreasing oil viscosity. CO2 is separated from the oil at the surface for re-injection. Large volumes of CO2 can be stored in the reservoir upon completion of the EOR activities.|
|CO2 utilisation per tonne of product output||CO2 injection per oil displacement rate is very dependent on reservoir’s characteristics (e.g. size, pressure, temperature, etc). The Weyburn,project injects around 0.5 tCO2 per incremental barrel oil displaced (Enhanced Oil Recovery Institute, 2007). As stated, this varies dramatically and would need to be examined on a site-by-site basis.|
|CO2 source||Commercial scale CO2-EOR injection, such as that occurring in West Texas, predominantly use naturally occurring CO2 reservoirs, though CO2 captured from industrial sources can also be used, as it is at Weyburn.|
|Technology status (includes project status)||CO2-EOR is a proven technology with many projects in operation including:The Rangely project in the US has been using CO2 for EOR since 1986, sourcing the CO2 from the LaBarge field in Wyoming. 23–25 Mt have been stored since 1986, nearly all of which is considered to be dissolved as aqueous CO2 and bicarbonate.At Weyburn, about 2.8 Mt a year of CO2 is captured from a coalplant, transported to Saskatchewan, and injected it into declining oil fields (IEA 2010).Recent projects supported under the American Recovery and Investment Act allow for capture and storage of 4.5M tonnes of CO2 annually from a plant in Louisiana and 1M tonnes of CO2 per year from existing steam-methane reformers in Port Arthur, Texas. In both cases, this CO2 will be used for enhanced oil recovery in the West Hastings oilfield starting in April 2014.|
|Funding/support||While the majority of EOR projects progress with industry funding alone, a large proportion of proposed CCS projects in North America rely on EOR revenue as well as public funding.The DOE is sponsoring a range of studies and projects involving the application of EOR to CCS development.|
|General benefits||Increased oil revenue through CO2 storage. Return on investment through oil production should assist industrial CCS roll-out in the short term, and EOR is likely to materially assist the development of early CCS demonstration projects. Combined with MMV, EOR also has the potential to enhance understanding of sub-surface CO2 migration and to foster community acceptance of geological storage.|
|General barriers||EOR is not technically feasible in all depleted or depleting oilfields, and the capital cost of implementing EOR may be prohibitive in many situations, so its deployment will be restricted to favourable locations. That still leaves substantial scope for the expansion of EOR, however, particularly if it can attract revenue from emission mitigation credits as well as from oil production.|
Refer to Appendix A for further details of CO2 for Enhanced Oil Recovery (EOR).
A technology which is analogous to CO2-EOR is CO2 enhanced gas recovery (EGR). EGR refers to incremental gas recovery from depleted conventional gas reservoirs. EGR differs from EOR in that the mechanism for the enhanced gas recovery in theory relies on physical displacement (upwards) of the lighter natural gas by the heavier CO2, with minimal mixing. This is in contrast to EOR, which typically relies on miscible mixing of oil and CO2 to decrease oil viscosity.
EGR is distinct from ECBM and has received limited attention compared to CO2-EOR. This is due to its level of immaturity in comparison to ECBM and due to the limited information available. To date only one pilot experiment has been conducted by Gaz Dein the North Sea at the K–12B field in the offshore Netherlands, which has been terminated.
Currently, EGR does not present itself as a lucrative opportunity due to the relatively high initial recovery characteristic of gas reservoirs (typically more than two thirds of the gas in place). The economics of EGR are not strong, or the technology would be further developed. Specific case study simulations for EGR have suggested a breakeven CO2 price of US$8/t with a wellhead natural gas price of US$2.85/GJ, clearly indicating that revenue from reuse would be very modest.
For the purpose of the current study, EGR is considered to be part of EOR as a short-listed item. Since EGR is so immature in comparison to ECBM and due to limited information available, the technology analysis throughout the report will focus on CO2 for EOR. However, the potential for EGR may improve in the future as world natural gas prices rise, and it should not be dismissed from future consideration. Furthermore, by their nature, former gas reservoirs have demonstrated a capacity to retain gas, which makes them an obvious target as a CO2 sequestration site (and the potential complimentary revenue from incremental natural gas recovery will not go unnoticed).
In summary, EGR is undeveloped, has very marginal economics at current gas prices and consequently has not been considered as a separate short-listed technology. However, EGR can effectively be considered as part of EOR as a short-listed item. In particular, if natural gas prices rise into the future, the economics and characteristics of EGR may look very similar to EOR.
Urea accounts for almost 50 per cent of the world’s nitrogen fertiliser production. It is produced by combination of ammonia and carbon dioxide at high pressure and temperature. Normally, CO2 is sourced from the process of reforming natural gas (or a similar feedstock) to produce ammonia. In this regard, urea production can predominantly be considered a ‘captive’ use of CO2 (i.e. CO2 is produced and then used within the same industrial process).
However, when natural gas is the feedstock for urea production, there is typically a small surplus of ammonia (approximately 5 to 10 per cent), which could be reacted with externally supplied (non-captive) CO2 to produce additional urea. Reformer flue gas capture plants have been installed at several urea production facilities to capture CO2 for this purpose, particularly by Mitsubishi Heavy Industries, and the technology can be considered mature.
Figure 2.2 Urea fertiliser production overview
Table 2.2 Urea yield boosting summary
|Technology||Boosting yields of conventional fertiliser production facilities|
|Proponents||Multi-national industrial scale fertiliser production firms|
|Description||Urea production plants using natural gas as a feedstock tend to produce a small surplus of ammonia. Captured CO2 can be reacted with surplus ammonia to form urea.Urea is one of the most common types of solid nitrogen fertilisers. The final product is typically a granulated solid. Once applied to agricultural land, urea reacts with water to release the CO2 and ammonia. The CO2 returns to atmosphere and the ammonia decomposes further supplying nitrogen to the crops.Urea can also be used to produce Urea-Ammonium Nitrate (UAN), one of the most common forms of liquid fertiliser.|
|CO2 utilisation per tonne of product output||For every tonne of urea produced, 0.735–0.75 tonnes of CO2 will typically be consumed.|
|CO2 source||The CO2 source for urea yield boosting is typically CO2 captured on-site from reformer flue gas.|
|Technology status (includes project status)||Urea has been produced on an industrial scale for over 40 years. CO2 capture plants for urea yield boosting have been installed since late 1990’s. The technology is relatively mature.|
|General benefits||None identified|
|General barriers||None identified|
Refer to Appendix B for further details of CO2 for urea yield boosting.
2.3 CO2 as a working fluid for enhanced geothermal systems (EGS)
Enhanced geothermal systems (EGS), also known as hot fractured rocks (HFR) or(HDR), is an emerging geothermal technology whereby subsurface hot rocks that are not naturally suitable for geothermal energy extraction can be made so through engineering procedures. The requirement for significant engineering work prior to heat extraction distinguishes EGS from conventional geothermal applications. A new approach to this concept is currently being pursued whereby supercritical CO2 is circulated as the heat exchange fluid (or working fluid) instead of water or brine to recover the geothermal heat from the reservoir. It can also be used as the working fluid of the power cycle in a supercritical CO2 turbine.
Figure 2.3 Enhanced geothermal systems overview
Table 2.3 Enhanced geothermal systems summary
|Technology||Supercritical CO2 as working fluid in enhanced geothermal systems (EGS)|
|Proponents||GreenFire Energy / Enhanced Energy Resources (Joint Venture)Geodynamics LimitedSymmyx Technologies|
|Description||Supercritical CO2 is circulated as the heat exchange fluid (or working fluid) instead of water or brine to recover the geothermal heat from the reservoir. The CO2 may also be used directly as the power cycle working fluid in a supercritical CO2 turbine before being sent back to the reservoir.|
|Products||Geothermal energy for use in electricity generation|
|CO2 utilisation per tonne of product output||Based on long term reservoir pressurisation/fluid loss studies-potential capability to continuously sequester 24 tonnes of CO2 per day per MWe by fluid diffusion into the rock mass surrounding the HDR reservoir. However, this will be site specific.|
|CO2 source||CO2 in a pure, dehydrated state (industrial grade), suitable for compression|
|Technology status (includes project status)||Status of EGS – Pilot projects are currently either operational or under development in Australia, the United States, and Germany. However EGS using supercritical CO2 is at a very early stage of development and is yet to be tested at demonstration scale.(1) Joint venture of GreenFire Energy with Enhanced Oil Resources plan to build a 2MW CO2 based demonstration plant near the Arizona-Newborder. Drilling of wells to access hot rock is proposed to commence in 2010. The proposed location is projected to yield enough heat to generate 800 MW of power with potential to absorb much of the CO2 generated by six large coal-fired plants in the region.(2) Geodynamics Limited Innamincka ‘Deeps’ Joint Venture with Origin Energy: a 1 MW power plant has been constructed at Habanero. Electricity generation is expected to occur by early 2012 following the successful completion of Habanero 4 and Habanero 5 (reservoirs). This will be the first enhanced geothermal system in Australia.Due to make on proposed $300 million, 25MW geothermal demonstration plant in the Cooper Basin by early 2013, after 12 months of successful operation of the Habanero closed loop. (This is two years later than previously stated).Testing the use of supercritical CO2 as the working fluid in geothermal systems is projected to commence in 2013.|
|Funding/support||U.S. Department of Energy recent award of US$338 million in federal stimulus funds for geothermal energy research.|
|General benefits||The significant density difference between the cold SCCO2 in the injection well and the hot SCCO2 in the production wells provide a large buoyant drive (thermal siphoning) and markedly reduce the circulating pumping power requirements of a water-based Hot Dry Rock (HDR) system.Inability of SCCO2 to dissolve and transport mineral species from the geothermal reservoir to the surface would eliminate scaling in the surface equipment (piping and heat exchangers).HDR reservoirs with temperatures > 375ºC (the critical temperature for water) could be developed without problems associated with silica dissolution.Much larger flow rates can be achieved with CO2 than can be achieved with water due the lower viscosity of CO2.|
|General barriers||EGS for power generation is still relatively novel technology and remains to be proved on a large scale.The lifetime of HDR geothermal system may be difficult to prove.There are a number of significant issues that need to be resolved. These include theof supercritical CO2, the corrosive conditions that arise with CO2 in contact with reservoir water, and long term effects in terms of reservoir connectivity, the source of CO2, the long term retention of CO2, and design and optimisation of power generation systems to work with supercritical CO2.CO2 has a lower specific heat capacity than water, and so greater flows are required to achieve the same heat extraction.Potential barriers to implementation include access to CO2 at an acceptable cost, proximity of the EGS to the electricity grid, and access to cooling water.Similar issues related to long term responsibility for the resultant reservoir, including the liability for future CO2 leakage.There is concern in the Geothermal industry that carbon capture/CCS is a transitionary technology and availability of CO2 in the very long term is raised as a concern.|
Refer to Appendix C for further details of EGS technology using supercritical CO2 as the working fluid.
2.4 CO2 as feedstock for polymer processing
A new approach to polymer processing is to combine traditional feedstocks with CO2 to synthesise polymers and high value chemicals. The technology transforms carbon dioxide into polycarbonates such as polypropylene carbonate and polyethylene carbonate, using a zinc-based catalyst in a reaction with epoxide molecules.
Table 2.4 Polymer processing summary
|Technology||CO2 as feedstock for polymer production|
|Description||Novomer’s technology uses carbon dioxide as a feedstock to synthesise chemicals and materials for a number of every day applications.The technology transforms carbon dioxide into polycarbonates using a proprietary zinc-based catalyst system. The chemicals and materials produced contain up to 50 per cent carbon dioxide or carbon monoxide.|
|Products||Polymer coatings, plastic bags, laminates / coatings, surfactants for EOR, automotive and medical components.|
|CO2 utilisation per tonne of product output||Novomer’s plastics are made from 50 per cent fossil fuels and 50 per cent CO2.For each tonne of Novomer’s plastics manufactured, up to one half tonne of CO2 can be sequestered.|
|CO2 source||CO2 will be sourced from a waste stream, e.g. fromfermentation, reformers, natural gas wells, flue gas from coal-fired power plants, etc.The CO2 sourced from industrial emissions is likely to require some degree of purification.|
|Technology status (includes project status)||Novomer has been producing CO2 based plastic material on a pilot scale at Kodak Speciality Chemicals facility in Rochester, NY, since December 2009. Pilot scale plant is based on a patented technology developed by Cornell University.|
|Funding/support||In March 2010, Novomer was awarded US$2.1 million in the first phase of a potential US$25 million federal stimulus grant for sustainable materials production from the U.S. Department of Energy (DOE).Novomer is preparing an application for a follow-on Phase two award for a 24-month, approximately US$23 million project. This is subject to further DOE evaluation and approval.|
|General benefits||The use of carbon dioxide and carbon monoxide as feedstock, instead of the corn-based feedstock used by other biodegradable plastics, means that the production of plastic will not compete with food production.Traditional chemical industry infrastructure can be used to manufacture the plastic.|
|General barriers||Technology is still at a relatively early stage – it has only been demonstrated at a small scale (using a batch reactor).|
Refer to Appendix D for further details of using CO2 as a feedstock for polymer production.
The injection of CO2 may improve the economics of algal growth systems, making it a potential volume user of concentrated CO2 streams. As with CO2 supplemented atmospheres in industrial greenhouses, bubbling CO2 through algal cultivation systems can greatly increase productivity and yield (up to a saturation point). There is currently significant interest in the potential of algae to produce oil (mostly with a view to liquid transport fuel substitutes) at a price that is competitive with crude oil.
Table 2.5 Algae cultivation summary
|Technology||CO2 absorption by microalgae to generate biomass.|
|Proponents||Algenol, USSolazyme, USMDB Energy, AU|
|Description||Bubbling CO2 through algal cultivation systems can greatly increase production yields of algae. There has been significant interest in the last few decades in the potential of algae to produce oil at a price that is competitive with crude oil.|
|Products||The algalproduced can be processed in numerous ways to extract economic value, depending on the desired output product/s. Commonly, the natural oil fraction (some species are capable of producing 70%wt oil content) is sought as a feedstock for production, food products, chemicals, nutraceuticals or for cracking into smaller base units before reforming to a wide range of other products.|
|CO2 utilisation per tonne of product output||Typically, ∼1.8 tonnes of CO2 will be utilised per tonne of algal biomass (dry) produced, though this varies with algae species.|
|CO2 source||CO2 used in algae cultivation can be taken from a range of sources. One of the main sources investigated for large-scale production is power plant flue gases. Algae cultivation systems are biological systems and so have sensitivities to certain components and impurities. The source CO2 would typically go through some clean-up processes to remove any components, which may have a detrimental effect on the algae. Food grade CO2 could be considered the ideal source.|
|Technology status (includes project status)||There are currently no closed algal cultivation systems for biomass/biofuel production operating on a large scale, though there are many around the world emerging at pilot or demonstration scale, and it is no longer just a laboratory experiment. Several large global companies including BP, Chevron, Virgin and Royal Dutchhave invested research funding into various systems and are currently carrying out feasibility studies.|
|Funding/support||Several multi-billion dollar programs now exist driven by oil majors, with large multi-disciplinary research collaborations now underway at a number of universities in the US, Australia, NZ, Japan, China,and Europe.Support has been granted by the Mexican government and Presidency, for the aforementioned project by Algenol and BioFields in the Sonora Desert.|
|General benefits||Has high potential for large scale reuse of CO2Algal oil can be injected into existing crude oil refineries.Use of algae derived energy carriers (biofuel, biogas) results in displacement of fossil equivalents.|
|General barriers||Capital intensity of cultivation systems is currently a limiting factor.Requires large amounts of nutrients similar to existing agricultural systems, most of which are currently CO2 intensive in production, though in a captive system these can be managed more effectively and ‘recycled’.|
Refer to Appendix E for further details of algae cultivation using CO2.
2.6 CO2 as feedstock for carbonate mineralisation
Carbon mineralisation is the conversion of CO2 to solid inorganicusing chemical reactions. In this process, alkaline and alkaline-earth oxides, such as magnesium oxide (MgO) and calcium oxide (CaO), which are present in naturally occurring silicate rocks such as serpentine and olivine or in natural brines, are chemically reacted with CO2 to produce compounds such as magnesium carbonate (MgCO3) and calcium carbonate (CaCO3, commonly known as limestone). The carbonates that are produced are stable over long time scales and therefore can be used for construction, mine reclamation, or disposed of without the need for monitoring or the concern of potential CO2 leaks that could pose safety or environmental risks.
Figure 2.5 Calera CMAP process overview
Table 2.6 Carbonate mineralisation technology summary
The numbering scheme above will be retained throughout the table to differentiate between the two technologies.
|CO2 utilisation per tonne of product output||
|Technology status (includes project status)||
|General benefits||The Calera process has the following benefits:
Both the Calera process and Skymine technology have the following benefits:
|General barriers||General barriers to the Calera process:
Refer to Appendix F for further details of using CO2 as a feedstock for mineralisation.
2.7 CO2 for use in concrete curing
Canadian company Carbon Sense Solutions Inc.(CSS) is seeking to use a point source of CO2 to limit the need for heat and steam curing of precast concrete products. Instead of the traditional energy intensive steam curing technologies, the proposed CSS concrete curing process consumes carbon dioxide from onsite flue gases and local combustion sources to cure precast concrete products, with claimed equal material performance to the traditional curing process.
Table 2.7 CO2 for use in concrete curing summary
|Proponents||Carbon Sense Solutions Inc. (CSS)|
|Description||Point source emission of CO2 used to limit the need for heat and steam in the curing process in the production of precast concrete products.|
|Products||Precast concrete products.|
|CO2 utilisation per tonne of product output||Estimated at less than 120kg CO2/t precast concrete produced.|
|CO2 source||CO2 captured from industrial sources, ideally from sources within close proximity to the concrete plant.|
|Technology status (includes project status)||Technology is currently moving towards a small-scale demonstration. It remains to be proven.|
|Funding/support||No external funding or support received.|
|General benefits||Producers will benefit from energy and water reductions resulting in cost savings and efficiency gains. The proponent claims the process is easily retrofitted, requiring targeted modifications to existing plant machinery with minimal disruption to existing processes. It is also claimed that the use of CO2 results in an accelerated curing process with lower temperatures required.|
|General barriers||The concrete sector operates within a highly competitive commodity market with limited capital to invest in new technologies. The change in production method (curing process) must not compromise material performance as the material performance is governed by industry standards (e.g. ASTM, CSA).|
Refer to Appendix G for further details of using CO2 for concrete curing.
2.8 CO2 for use in bauxite residue carbonation
The extraction of alumina from bauxite ore results in a highly alkaline bauxite residue slurry (known as ‘red mud’), with a pH of approximately 13. The bauxite residue contains a mixture of minerals and some alkaline liquor (NaOH) from the Bayer extraction process. At Kwinana in Western Australia, Alcoa operates a residue carbonation plant, where gaseous CO2 from a nearby ammonia plant is contacted with the red mud slurry, reducing the pH of the slurry to a less hazardous level.
Figure 2.6 Bauxite residue carbonation overview
Table 2.8 Bauxite residue carbonation summary
|Technology||Bauxite residue carbonation|
|Description||The extraction of alumina from bauxite ore results in a highly alkaline bauxite residue slurry known as ‘red mud’, which causes environmental and handling problems in disposal. Alcoa ofuses a stream of CO2 from a nearby ammonia plant, contacting the CO2 with the red mud slurry to reduce the pH of the slurry to a less hazardous level for easier handling.Note: Brine is not utilised in Alcoa’s bauxite residue process.|
|Products||When alkalinity is neutralised sufficiently, the product can be used as aggregate material for mine reclamation / construction.|
|CO2 utilisation per tonne of product output||Red mud treated with sea water has a large theoretical capacity to absorb CO2 (up to 750kg CO2 / t red mud). However, Alcoa only proposes a level of 30-35kg per tonne of red mud (dry weight), as this is what is required to convert all of the alkalinity to carbonates.|
|CO2 source||At present, the process at Kwinana is only economical because of the availability of a low-cost source of high concentration CO2 from the adjacent ammonia plant. Alcoa advises that they currently believe the system requires concentration above 85 per cent – the process requires the CO2 to be in direct contact with the thickened slurry for reasonable holding time – a more dilute gas makes this difficult. An alternative process is proposed to utilise flue gas from captive power generation at Alumina refineries.|
|Technology status (includes project status)||Alcoa of Australia operates this process commercially at their Kwinana Alumina refinery, utilising a concentrated stream of CO2 from an adjacent Ammonia Plant, which is transported 8km by pipeline to the residue carbonation plant.Alcoa’s patents on the technology have expired, but they are offering other alumina producers a ‘technology transfer’ package that includes their more detailed intellectual property.Alcoa has also recently patented an integrated carbon capture and residue carbonation process that would allow the use of flue gas from captive power generation plant emissions.|
|Funding/support||No external funding or support received so far.|
|General benefits||Improves the handling and dusting characteristics of red mud, and reduces the costs of its disposal. Potential for use of the carbonated red mud as a soil amendment for acidic soils (see also http://www.csrp.com.au/projects/alkaloam.html).|
|General barriers||The prospects for implementation are restricted to alumina refineries with ready access to high concentration CO2 sources, and the scale of potential application is restricted by the limited prospects of material product revenue generation and by the relatively low levels of storage per tonne of bauxite residue.|
Refer to Appendix H for further details of using CO2 for neutralising bauxite processing residues.
2.9 CO2 as a feedstock for liquid fuel production
CO2 as a feedstock for liquid fuel production is a broad category for CO2 reuse, which includes conversion of CO2 to a number of alternative fuel products, including formic acid, methanol, dimethyl-ether, ethanol, and other petroleum equivalent products. To produce these varied end products, a range of CO2 conversion technologies are proposed.
In general, the primary energy input for these conversion technologies is renewable energy, with the current proponents focused on solar and geothermal energy. This is an important requirement for these technologies, as generally they have relatively low thermal efficiency (e.g. relatively small fraction of the energy input is converted to useful fuel). It should be noted that only renewable methanol production and formic acid production (as aenergy carrier) have been evaluated in detail in the current exercise, predominantly due to a lack of publicly available information for the other proposed technologies.
Figure 2.7 Renewable methanol production overview
Figure 2.8 Formic acid production overview
Table 2.9 Liquid fuel production summary
|Technology||CO2 to Liquid FuelsA range of technologies fall under the category of CO2 to liquid fuels technologies, and these are at varying stages of development. These technologies typically require renewable or zero-emissions energy inputs in order to achieve reduced CO2emissions relative to fossil fuels.More developed technologies include:
Less developed technologies include:
The above numbering scheme will be retained throughout the table.
|CO2 utilisation per tonne of product output||Assuming a gasoline-equivalent product, CO2 utilisation would be approximately 3.1 metric tonnes per tonne of liquid fuel.|
|CO2 source||Flue gas from power plants and other industrial sources|
|Technology status (includes project status)||
|General benefits||CO2 is essentially an energy carrier – the energy input can be from renewable or low emissions sources.|
|General barriers||Low efficiency (typically).High capital cost (anticipated based on technology descriptions available).Main application would be for transportation fuels. However, alternative transport systems (such as electric vehicles with regenerative braking coupled to a renewable energy powered electricity grid) may be a more competitive solution, with significantly higher overall energy conversion efficiency.|
Refer to Appendix I for further details of utilising CO2 as a feedstock for liquid fuel production.
2.10 CO2 for use in enhanced coal bed methane recovery (ECBM)
Coal bed methane is a useful source of energy and is increasingly extracted and used to supplement conventional natural gas supply. Normally, extraction is achieved by drilling wells into, and below, deep un-minable coal seams, and pumping out the water which naturally saturates the seam. This has the effect of reducing the hydrostatic pressure and causes the gas to be released from the coal. The gas is separated from the water at the surface, after which time, it can be utilised in the same applications as conventional natural gas.
In principle, the production of coal bed methane can be enhanced by injecting CO2 into the partially depleted coal seam where it is preferentially adsorbed into the coal, thereby displacing methane, which is released as further production to the surface. In practice however, the adsorption into the coal of CO2 causes it to expand and close up the fissures that provide the pathways andfor both gas production and gas injection. The benefits that arise from CO2 injection, of flushing out residual methane from the coal, may therefore be progressively offset by a reduction in permeability that inhibits methane production and CO2 injection. Further research and trials are required to establish whether and how ECBM can be developed so that the benefits decisively outweigh the offsets.
Table 2.10 Enhanced coal bed methane recovery summary
|Technology||Enhanced coal bed methane|
|Proponents||Interest in CO2 ECBM is focused on developed economies with large coal reserves, such as the US, Europe, Canada, Australia andand where there is funding to support development of the technology.Research is being undertaken by these countries’ scientific organisations, including CSIRO, NETL, AITF, and JCOAL amongst others.China United Coal Bed Methane Corporation is involved in several research/ demonstration projects. In the US, Consol Energy operates a pilot injection project funded by the US DOE.|
|Description||ECBM involves flooding coal seams with injected CO2, where it’s adsorbed by coal, in turn displacing methane to the surface for it to be captured and consumed as fuel.|
|Products||Natural Gas (Methane).|
|CO2 utilisation per tonne of product output||CO2 injection per gas displacement rate is very dependent on the reservoir’s characteristics (e.g. size, pressure, temperature). A study carried out in Alberta, Canada, found the injection recovery rate for CO2 to CH4 is 2:1 on a volume basis. As stated, this could vary dramatically and would need to be examined on a site by site basis.|
|CO2 source||Naturally occurring CO2 reservoirs and CO2 captured from industrial sources.|
|Technology status (includes project status)||ECBM recovery is a developing technology, to date trialled on a pilot scale.|
|Funding/support||A number of countries with large coal resources are investigating the potential of ECBM and are funding research to better understand the process and to overcome the constraints on injectivity. Developing countries with growing energy demands and large coal resources, likeand Indonesia, are also investigating ECBM potential.|
|General benefits||Increased natural gas revenue through CO2 storage. Return on investment through natural gas production could assist industrial CCS roll-out in the short term. Permanent storage of CO2 once injected in a coal seam.|
|General barriers||The technology is at an early stage of development. It is not yet clear whether and how its theoretical methane displacement benefits can decisively outweigh the permeability deterioration offset that accompanies CO2 injection.|
Refer to Appendix J for further details of using CO2 for Enhanced Coal Bed Methane Recovery (ECBM).