3.3 Storage and use
This section provides an update to the fundamental overview of storage which was provided in the 2010 Status Report (Global CCS Institute 2011a) and covers the progress of storage, resource assessments and of work on storage issues and methods. It also covers some developments in the use or utilisation of CO2, which is increasing in importance, particularly to provide commercial drivers for CCS demonstration projects.
Progress in regional/national storage assessment
There has been additional progress on screening of potential deep saline formations in some nations since the beginning of 2011. Grant programs, for example, the EU Figure 36.and the Australian Flagships program, including the National CO2 Infrastructure Plan, are stimulating new storage screening and more detailed site assessments. Brazil’s Centre of Excellence in Research and Innovation in Petroleum, Mineral Resources and Carbon Storage (CEPAC) has also progressed a program. This progress by is reflected in the current status of country-scale storage screening assessments shown in
Figure 36 Current status of country-scale storage screening assessments. Source: IEAGHG 2011, modified by the Global CCS Institute
Brazil has taken a multidisciplinary approach to its source-sink matching for assessment of potential applications of CCS. CEPAC completed a Geographic Information System (GIS) based database of CO2 sources and sinks in 2010. CEPAC is currently reviewing and refining database content within its Brazilian Carbon Geological Sequestration Map (CARBMAP) program, which commenced in 2007 (Rockett et al. 2011). The project has ranked onshore and offshore basins and delineated the greatest potential as being in the Campos and Parana basins (petroleum reservoirs, deep saline formations and coal beds). Theoretical capacity estimates have been established for depleted petroleum reservoirs, with the majority share (1.7Gt) in the Campos Basin (Figure 37).
In March 2011,commenced reinjecting associated CO2 (up to 0.7Mtpa at peak production) into the Lula giant oil field in 2150m of water depth offshore of Rio de Janeiro. This injection occurs within the Santos Basin pre-salt fairway and follows onshore pilot testing in 2009 (Elsworth 2011).
Figure 37 Brazil sedimentary basins. Image courtesy of CARBMAP, Brazil
China’s storage potential assessments are very high level in nature as the focus has been largely on using CO2 for EOR and other industrial applications, rather than permanent geological storage. Despite this, efforts to assess and characterise China’s CO2 storage capacity continue. The Chinese Geological Survey is currently conducting a survey of China’s storage capacity, which is scheduled for completion in 2012 (MOST 2010).
At a project level,is making good progress in developing and applying ways to utilise CO2. For example, China Petroleum and Chemical Corporation Limited (Sinopec) has captured and injected 0.04Mtpa of CO2 into Shengli oil field. Similarly, PetroChina has been injecting 0.12Mtpa of CO2 into Jinlin oil field since 2009. China Huaneng Group have two PCC projects that capture CO2 for use in soft drink production and other industrial uses, including a 3000tpa PCC pilot (Beijing) and 0.12Mtpa PCC project (Shanghai). The ENN Group China is currently operating a pilot project that uses CO2 microalgae production with plans to scale-up to a 0.32Mtpa pilot facility in Inner that will use the microalgae for production of bio-diesel and other biofuels.
TheGroup have commenced injection at the CTL Plant (Ordos City) in Inner Mongolia, aiming to reach 0.1Mtpa of CO2 injected into a saline formation. Sinopec plans to develop a 1Mtpa CCS project where the captured CO2 will be used in EOR at the Shenli oil field.
In Europe storage capacity assessments have continued at a national level.
In thethe UK Energy Technologies Institute (ETI) funded a comprehensive assessment of national CO2 offshore storage capacity at a cost in excess of £3.5 million. The CO2 Storage Appraisal Project (UKSAP) identifies the storage units, their theoretical storage capacity and the associated containment risks and economics. Started in October 2009, results were expected to be available around the end of August 2011 (UKSAP 2010).
The EC continues to support research into better defining storage capacity through the issue of tenders and the Framework Programme 7 (FP7) call for projects. Their ‘SiteChar’ three year research projects were launched in January and May 2011 and the FP7 call also includes new storage related topics.
Of the thirteen project proposals submitted to the EIB under the NER300 funding program on 9 May 2011, four onshore and nine offshore storage projects have been proposed to investigate CO2 storage in deep saline formations or depleted hydrocarbonand through EOR/enhanced gas recovery.
In Europe six European projects (Jänschwalde, Don Valley, Porto Tolle, ROAD, Bełchatów and Compostilla) signed an agreement with the EEPR (2010) in 2009–2010 to share and disseminate the results of their technological advances and project progress through the EC initiated European CCS Demonstration Project Network.
Theis supporting storage programs including the RCI depleted field assessment in the southern North Sea and the Romanian Getica project (see case study textboxes).
Finally, the Norwegian Government continues to support R&D, transport and subsea storage solutions and mapping of relevant sites. By 2010 the Norwegian operating projects, Snøhvit and Sleipner, had stored 1.0Mt and 13Mt of CO2 respectively in deep saline formations (Ringrose et al. 2011).
Case study - Romania
Thewas initiated by the Romanian Government in 2010. It is located in the Oltenia region, the most energy intensive region in which is responsible for about 40 per cent of the country’s total CO2 emissions. CO2 captured from the Turceni power plant is to be stored in deep saline approximately 50km from the power plant.
- A storage was conducted in 2010 and 2011 by GeoEcoMar with technical support from Carbon Services where existing geological, geophysical and well data was collected.
- Preliminary site screening included eleven sites of which two are considered suitable (Zone 1 and Zone 5) for storage and will be the object of further characterisation studies.
Case study - The Netherlands
The(RCI) was launched in 2006 by the port and city of Rotterdam for municipal and regional authorities to work with the corporate sector and cut CO2 emissions by half by the year 2025 while adapting to climate change and promoting the regional economy.
To evaluate storage options by 2015, RCI initiated in 2010 an ‘Independent Storage Assessment’ of the Dutch offshore depleted hydrocarbon fields, carried out byand published in 2011 (Neele et al. 2011).
- In the first phase existing data was collected and reviewed, leading to a detailed and comprehensive database on the P and Q Blocks of the Dutch Continental Shelf, including its geology, wells and well-related data and hydrocarbon production history.
- In the second phase a detailed feasibility study was conducted for the most promising fields: P18, Q8-A and K12-B.
- P18 is the main candidate for the ROAD (Rotterdam Opslag en Afvang Demonstratieproject) CCS demonstration project. Total investment costs for P18 is estimated to be €65 million, for workover of platform and six wells, excluding onshore installations and pipeline construction. Operational costs are of the order of €3.2 million a year; these do not include the costs of (remotely) operating the platform.
The Institute’s 2011 project survey has tried to identify the stages that individual components (capture, transport and storage) have reached to understand the relative progress within an LSIP between these components. As storage characterisation is site dependent, and arguably requires the longest lead times, it can often end up lagging behind the progress on capture. However, it is important that storage assessment is at least as advanced or even more advanced than other components in the CCS chain, particularly for greenfield deep saline formation sites, as opposed to EOR or depleted oil and gas reservoirs which have previously been investigated.
In Canada, the Boundary Dam project moved into the Execute stage in April 2011 and is expected to begin capturing 1Mtpa of CO2 in 2014. While much of the captured CO2 will be targeted towards EOR activities, a significant portion initially captured is expected to be integrated into the Aquistore geological storage project. Aquistore will target basal Cambrian-Ordovician strata within the Williston Basin as the storage complex. The Illinois-ICCS project has also commenced construction in 2011 and plans to initially store the CO2 in a deep saline formation. Theproject is anticipated to move to Execute in 2012 and plans to store CO2 in the basal Cambrian deep saline formation sandstone, similar to Aquistore.
Project development complexities and timeframes will constrain the likelihood of more than one or two additional deep saline formation LSIPs operating in the next three years, regardless of funding or grant conditions.
When projects are less advanced in storage than in the other components, this misalignment may lead to a delay in the timelines for the integrated projects. Notably, the Quest project is very advanced in its understanding of its storage component and is thereby enhancing its chances of meeting delivery timeframes.
Timelines for storage assessment
Based on results from the 2011 project survey, the estimated lead times for greenfield storage assessment remain at five to 10 years or more. Often it is the project risks and activities required to progress from the Define to the Execute stage which creates these extended timeframes.
Many countries (Figure 36) have now undertaken storage screening and have addressed the fundamental questions concerning the opportunity for adequate storage within their jurisdictions. In many countries it is known that there is reasonable potential for CO2 storage. While national-scale screening remains important, there is an increasing need to focus on maturing demonstration project storage sites and ‘learn by doing’.
Costs of storage
A recent study by ZEP (2011) identified the magnitudes by which onshore storage presents lower costs relative to offshore storage, as well as the extent to which depleted oil and gas fields present cost savings relative to deep saline formations, particularly if there are re-usable legacy wells (Table 7). Despite the relative cost advantages of certain options, ZEP noted that the lowest cost storage reservoirs contribute the least to total available capacity. That is, given the current understanding of reservoir capacity in Europe, there is more storage capacity offshore than onshore, and there is more storage capacity in deep saline formations than in depleted oil and gas fields. Overall, while characterising storage remains an essential part of CCS, the estimated costs of storage remain low in relation to capture.
Table 7 ZEP cost estimates for storage1
|€ per tonne of CO2||€ per tonne of CO2|
|Depleted oil and gas fields (legacy wells)||3||6|
|Depleted oil and gas fields (no legacy wells)||4||10|
|Deep saline formation||5||14|
1 Medium (or most likely) values from the ZEP scenarios presented.
Source: ZEP (2011)
Continuing and emerging issues in storage
The significance of CO2 EOR
While it is difficult to obtain precise quantities, it is clear that at present more anthroprogenic CO2 is geologically stored through EOR processes than through any other method globally. There is also considerable interest in both developing and OECD nations in CO2 EOR for domestic oil production. This is particularly true for China, MENA and increasingly, the North Sea. Although the vast majority of EOR has occurred within the United States, many other countries including Canada, China, Brazil, Hungary, Trinidad, andhave a history of CO2 EOR operations (Tzimas et al. 2005).
Not all oil fields are suited to CO2 EOR. Generally speaking, fields are suitable if they contain oils that are moderate to light, and relatively low in wax, and other precipitates. Further, the fields should operate at pressures high enough to enable CO2 to mix with the oil and form a single phase liquid, and have access to significant volumes of water, which is injected alternately with the CO2 in most current EOR operations to minimise the use of what is presently costly CO2. The oil recovery process should operate above the minimum miscible (mixing) pressure throughout the entire reservoir. Sufficient oil saturation in the reservoir (at least 35 per cent) should be present. In general, the more homogeneous the reservoir, the more effective the CO2 flood will be.
Approximately 80 per cent of CO2 used for EOR in theat present is from naturally occurring sources produced from the subsurface (Global CCS Institute and Parsons Brinkerhoff 2011), which leads to a net contribution rather than abatement of CO2 from the atmosphere.
Alternatively, in southern Saskatchewan, Canada, as of early 2011, a cumulative total of approximately 20Mt of anthropogenic CO2 has been stored in the Weyburn and Midale fields. Over the life of a CO2 EOR program, CO2 is produced from the oil, separated and reinjected, reducing the requirement for new CO2 supplies. Ultimately a field may require almost no new CO2, relying on the recycled CO2. Currently the Weyburn field injects about half ’new’ CO2 and half ‘recycled’ CO2. Essentially, all of the CO2 injected will remain in the reservoir zone aside from minor losses from operations or when intentional flaring is required.
Where recycling is not undertaken (for example the Joffre field in Alberta, Canada) approximately 30 to 40 per cent of the injected CO2 is permanently retained underground after the CO2 has migrated through the formation or ‘broken through’ to the oil producing wells. When a CO2 EOR field is no longer producing enough oil to merit continuing EOR, there is an opportunity to convert it to dedicated storage, should the incentives to store rather than extract and reuse CO2 be in place. In many cases though, the end of EOR production is many years in the future (between 15 and 35 years for example with respect to the Weyburn and Midale fields under present conditions).
Generally, current EOR operations are not set up for the detailed accounting anticipated for crediting permanent storage of CO2. Although many operators may measure the volumes of CO2 injected into the reservoir and the amount of CO2 recycled, they largely monitor the movement of the CO2 in the subsurface to optimise production. EOR operations are, in many jurisdictions, required to perform wellbore integrity testing and prevent any oil field influence on the soil or potable aquifer systems but not to monitor CO2 subsurface distribution.
For EOR to lead to abatement of atmospheric CO2, the following factors should be in place:
- the CO2 that is injected should be produced from human activity (anthropogenic) that would have otherwise been released to the atmosphere; and
- a system of crediting backed up by a monitoring system that demonstrates and measures net CO2 permanently stored must be established, including baseline monitoring.
There are a number of insights for CO2 storage that can be derived from EOR including:
- The easiest way to commence a CO2 project at present onshore is through EOR, as there are existing regulations and infrastructure in place. Moreover, EOR is presently the most cost-effective option to store anthropogenic CO2.
- Providing the knowledge is shared, CO2 EOR provides an understanding of the subsurface response to CO2 injection. There are more than 30 years of history of CO2 injection in oil fields as well as the lessons learned from long-distance CO2 pipeline transport. In addition, monitoring, measuring and verification methodologies can be tested if there are regulatory and/or economic incentives in place for the operator.
- The requirements and expectations for dedicated CO2 storage need to consider the pragmatic approach taken for EOR. For example, to what resolution do we need to know the extent of the CO2 or how far it may migrate and what are sufficient protocols to manage the impacts of variations from expected responses?
The Institute is currently examining the potential of EOR to impact on storage with reviews being undertaken of the technical, regulatory and commercial issues. In providing a revenue source for the CO2, EOR, with adequate MMV, can improve the viability of CCS projects while ensuring permanent storage.
Resource interaction, assessment and management
Sedimentary basins contain many different resources, either as part of the rock mass or as associated fluids, including coal, coal bed methane, oil, natural gas, shale gas, geothermal energy, water, salt and other minerals of value. The incursion of fluids such as CO2 can impact directly on other resources and also connected pressure systems, which may have both good and bad effects. These include, but are not limited to, assisting in production through increasing pressure (good) or mingling with the fluid and changing its chemical and physical properties (both good for example in EOR and potentially bad for example in decreasing the pH of water).
Resources extracted including petroleum, water or even heat have a more direct and immediate revenue value to a jurisdiction, through resource rents, production sharing or royalties, when compared to the broader environmental benefit derived through storage of atmospheric CO2 that is difficult to allocate. As a consequence, CO2 storage is often treated as the lowest value use of pore space by individual jurisdictions, particularly in the absence of a price on CO2 emissions, and must also demonstrate little or no risk of adverse impact on other resources.
World population pressures and climate change are increasing the scarcity and value of potable surface and near surface water. There is also increasing competition for deeper potable groundwater resources and concern about the impacts that resource activities may have upon them. However, CO2 storage will largely occur at greater than 800m below the ground surface, as below this depth the CO2 will be in a dense state. This is normally well below depths typically accessed for groundwater production (zero to 300m).
Production of hydrocarbons in the same area as carbon storage can and does occur successfully near current CCS projects (for example Sleipner, Snøhvit, In Salah, and Weyburn-Midale). In areas of active exploration for, or production of, energy resources, including coal bed/coal seam methane (CBM), shale gas, geothermal as well as more conventional petroleum, concerns can be raised about issuing multiple property rights over the same area. Specifically, these issues can include the hierarchy of those rights, as well as the potential impact on producing and non-producing wells as well as impacts on other resources in the vicinity.
In some cases the storage and resource extraction activities will occur at widely separated depths, in different strata and have little or no impact upon one another. For example, high temperature geothermal heat production for power generation will exploit zones where the subsurface temperatures are well above 120°C. This is generally at 3000m or more depth, beyond the depths at which CO2 storage will usually occur. Conversely, hydrocarbon exploration and production, CBM production and shale gas production, can all occur at similar depths to CO2 storage. But when conventional hydrocarbon production is separated from the CO2 injection interval by sealing rocks either above or below the producing interval, CO2 injection and production can overlap in an area and be active at the same time, as is seen at Sleipner and other fields (Eiken et al. 2010).
The activities associated with other subsurface resources can impact on the suitability of areas for secure CO2 storage. For example, some of the hydraulic fracturing (fraccing) methods used in developing shale gas can impair the containment properties for CO2 storage to the point where CO2 can no longer be stored under the fracced interval.
CBM production requires de-watering to depressurise the producing interval and free up methane through desorption from the coal. If the produced water is not suited to treatment for further use at surface, it may be disposed of in another interval in the subsurface. CBM may also compete for storage pore space for disposal of its waste water.
In summary, there are challenges in multiple resource use in the subsurface, but as long as that interaction is understood, CO2 injection and storage can be compatible with other subsurface resource activities. Modelling of fluid flow is vital to address and manage competing demands on a prospective injection target, particularly if there are concerns about impact on other resources.
Deep saline formations are considered to have the greatest potential by far to store large quantities of CO2. In saline formations, the pressures have not been depleted through production of hydrocarbons, unless they are in pressure communication with a hydrocarbon interval that has been produced.
Concerns about the ability to sustain long-term injection of CO2 in closed systems were discussed the 2010 Status Report. Pressure increases associated with injection of CO2 may attain a high enough level where the seal can fracture, thereby compromising the integrity of the storage complex. While this threshold can be accurately modelled and pressure monitored downhole, the large scale injection being considered in some projects necessitates careful monitoring of pressures within the deep saline formation.
An ‘open’ saline system has little or no barrier for some distance, so that CO2 injected can displace the saline water through the pore system. Modelling can predict the rates of pressure build-up and dissipation and be used to optimise the rate of CO2 injection. Zhou and Birkholzer (2011) have simulated injection into the Mount Simon Sandstone in theBasin, considered by the authors to be an ‘open’ system where there are no major lateral barriers to the movement of fluids (including CO2). They set up 20 hypothetical injection ‘projects’ about 30km apart. Using properties consistent for sealing formations in the basin the maximum pressure buildup over a 50 year period caused by 5Gt of CO2 injection does not breach the seal and is safely contained.
Zhou and Birkholzer (2011) argue that naturally closed systems are rare (a fault-bounded oil field being an example). Even in closed systems, seal integrity can be maintained through careful monitoring of pressures within and beyond the CO2 plume and if necessary by releasing some salty water through designated wells.
Monitoring Measuring and Verification for risk management
Wright (2011) presented a schematic risk profile through time illustrating that the risks during the lifecycle of a CO2 storage project are arguably at their highest near the later stages of injection, towards the end of the maximum injection rate plateau and then reducing rapidly following the closure of a facility (Figure 38). This profile is similar to that presented by Benson (2007) and points to the progressive reduction of risk post injection with time. Processes that occur over time to reduce the risk include pressure dissipation and residual trapping of the CO2 in the pore spaces.
Figure 38 Schematic risk profile for a storage project. Source: Wright (2011), based on In Salah
Note: Monitoring and verification (M&V) and quantified risk assessment (QRA)
Dodds et al. (2011) identified, as have others, the need for both environmental and geological baseline data, initial and ongoing risk assessment and monitoring strategies suited to the specific site prior to injection. This process will help ensure that changes in the subsurface potentially affecting the risk profile can be detected and addressed in a timely manner.
The fundamental objectives of a MMV program are to identify and manage risks by providing data to ensure operational procedures are progressing appropriately, to updateand to identify any deviation in the injection field behaviour. The methodologies that provide the most effective coverage and detection of movement of CO2 in the subsurface will need to be developed on a site by site basis. For example, in some cases this may mean that monitoring for pressures will provide an earlier and better understanding of the location and impact of the CO2 plume than seismic imaging, particularly where the signal quality is poor.
The monitoring strategy should be directed by the risk assessment and be fit for purpose—not unnecessarily prescribed. From the safety perspective, the fundamental outcomes should be minimising risk and ensuring containment.
If there is no methodology and protocol which can effectively monitor CO2 at a given site, then injection of large volumes of CO2 should not be pursued at that location until those methods are available and tested.
There is an expectation that early movers will pay a ‘precautionary premium’ to ensure safety but requirements should be based more on risk assessments and mitigations, rather than prescribed.
Storage risks for an individual project will generally decrease as time passes after injection ceases. The risk profile has reduced to a point that is an order, or orders of magnitude less than the maximum level during operation. It is expected that some monitoring will be required by the regulator during the post injection phase until it is established that the system is behaving as predicted and further risks are minimal. The assumption of risk/long term liability – whether it is the operator, jurisdiction or through some trust arrangement – should consider the decreasing risk profile when assessing their exposure.
Storage capacity development and training in developing nations
Given the importance of moving beyond desktop studies toward site specific characterisation, there is a need to increase skills and capacity in the storage disciplines; particularly in developing countries that still need to build a case for CCS.
In the first instance capacity development activities can focus upon supporting countries to undertake initial desktop storage studies, and there are examples of this taking place.released its National Storage Atlas in 2010 and has received funding from international funding bodies to undertake more specific desktop site studies.
However, the type of activities will need to expand as developing countries make the transition from national screening to characterisation. They could include: undertaking a technical capacity analysis of a country’s geoscience departments to identify technical strengths and gaps; addressing gaps by providing technical training forthrough storage workshops and courses; providing opportunities to visit sites; and engaging existing geotechnical networks and projects.
There are already a range of storage specific courses and programs including the Geologic Carbon Sequestration Program at Lawrence Berkeley National Laboratory and the Carbon Capture and Storage Masters Program at the University of Edinburgh. Organisations such as CO2CRC’s CCS Otway Demonstration Project in Victoria, Australia, often hosts site visits, as do other companies with CCS projects. The British Geological Survey has previously undertaken ‘skills gap’ analysis in developing countries and provides storage expertise in other international collaboration projects such as the Near Zero Emissions Coal (NZEC) and the Cooperation Action within CCS China-EU (COACH), both of which have a focus on China. The EuroGeoSurvey is an example of an existing knowledge-sharing network of 32 geological surveys which can be utilised to provide support to European based geosciences departments.
Gaps in storage understanding and future areas for work
Although petroleum exploration and production provides a sound and highly sophisticated foundation of tools and workflows in CCS, it also creates a bias that may restrict consideration of techniques outside of the current petroleum toolkit. At the highest level, petroleum explorers are focussed on the oil or gas producing qualities of the reservoir. By contrast the most important consideration for CCS storage is seal or containment ‘caprock’ above the storage formation.
There has been significant progress in understanding the response on subsurface equipment and materials to CO2 and ways of managing the impact (for example Smith et al. 2011). There is also a much better understanding of how different impurities will impact on the subsurface infrastructure (such as well casing and cements), and injection performance, as well as a recently internationally released framework for risk management of existing wells (DNV 2010).
Finding alternative methods of measuring the extent of the stored CO2 in formation and its far field effects is an important area that requires field testing.seismic has been successful as a tool to directly measure the extent of CO2 in some thick intervals with high porosities (such as Sleipner) but generally has been less successful in thinner intervals with lower porosities (such as In Salah). Seismic acquisition can be intrusive onshore—for example, it can require temporary removal of fencing—particularly if it is undertaken repeatedly in areas of multiple use. All seismic monitoring is costly.
Satellite methods such as InSAR are attractive as they are low in cost and unobtrusive. They have been used at In Salah to measure at a millimetre scale the slight land surface deformation caused by injection, but require quite specific surface conditions including limited or no vegetation cover. Dedicated permanent markers and other tools are being developed to cope with vegetation cover (for example at the MGSC’s Decatur project).
- coupled non-linear geological, geomechanical and geochemical processes;
- plume profiles in heterogeneous reservoirs to determine capacity factors;
- modelling trapping mechanisms;
- develop and refine the numerical simulators needed to design and interpret the pilot test data;
- compare a number of simulators to develop confidence in numerical approaches;
- fault stability assessment and analysis;
- transport properties – trap integrity and trapping mechanisms;
- rock deformations;
- thermodynamics of complex fluids and solids;
- chemical properties and geochemical transport understanding in different formations;
- understand current models and their limitations;
- experiments to define improvements;
- monitoring – dynamic imaging of plume;
- remote sensing – non invasive techniques; and
- reliability of 4D monitoring.
The challenge remains to develop alternative less costly and intrusive methods of assurance monitoring of CO2 containment and have them accepted by regulating agencies and other stakeholders. This may involve redefining the problem from optimising direct image quality of the CO2 plume to confident but indirect detection methods of determining plume effects.
Solutions may involve less direct imaging techniques, greater integration of different tools that can help constrain results and a greater focus on early warning systems for potential future containment problems, coupled with robust responses to avert leakage. For example, pressure monitoring beyond the plume with slimhole monitors may be both a more effective and cost effective alternative, or possibly complementary to, lower quality seismic data.
Storage assessment and monitoring strategies must be adapted to the specific site. The clear need now is to operate storage in real geological systems to test and broaden the number of methods available for measuring and monitoring the response of the Earth to the injection of CO2. Matching the predicted outcomes with the actual results will improve the predictions and increase the knowledge and confidence in storage. Most importantly, the extent of the impacts of CO2 injection (including far field pressure effects) needs to be predictable, measureable and understood with mutually agreed limits between the operator and regulator.
When the CO2 is injected a number of responses still need to be better understood, including but not limited to:
- The response at the intersection of the sealing ‘caprock’ and the top of the storage reservoir when CO2 reaches the interface, as there is a possibility that the cooler CO2 could lead to some fracturing.
- The inelastic behaviour of rocks when storage occurs in depleted reservoirs, as the rocks do not necessarily return to the same state when they are ‘repressured’ again using CO2. In some cases this may mean that there is a greater risk of fracturing when CO2 is injected.
Use of CO2 and ‘Novel’ CCS
Algal biofuels, reforestation, increased wood based construction, mineral fixing and soil sequestration have been considered as potential ways of storing CO2 as well as providing other resource benefits. The key differences between these methods and geological storage, at least for the present, is the ’permanence’ and quantity of storage. Unless the CO2 is removed from the carbon cycle it does not remove the carbon from the atmosphere in the long term. However, it may reduce net extraction of fossil fuels if it provides alternative fuels or materials that require lower fossil energy input.
Combining geological storage with capture of CO2 derived from the production or utilisation ofhas the overall effect of removing CO2 from the atmosphere. Bio-energy combined with CCS (BECCS) therefore goes and achieves ’negative emissions’. The most viable projects in this category are likely to be those, such as plants, that produce a high concentration stream of by-product CO2. CCS achieves its optimum cost efficiency at relatively large scale whereas biofuels projects are generally limited in scale by their access to feedstock. However a number of BECCS projects are now being considered in Europe and North America (Biorecro 2011).
CO2 use has an initial role to play in supporting the demonstration of CCS, especially in the absence of strong carbon prices. This role is clearly visible in the use of CO2 for EOR, as has already been described.
EOR is a commercial CO2 use application. Other use opportunities (Figure 39) are not as far progressed as industrial applications, as the source process does not supply concentrated CO2 or the use is a less permanent method of storage.
Figure 39 CO2 use technologies,concentration and permanence. Source: Global CCS Institute and (2011)
The Australian National Low Emissions Coal Research & Development (ANLEC R&D) and Brown Coal Innovation(BCIA) along with the Institute have commissioned a study to look more closely at the alternatives to geological storage of CO2 in Australia. With the obvious exception of wood-based construction these technologies are largely at a very early stage and the permanence of storage/fixing of CO2 ranges from months to decades rather than thousands to millions of years for geological storage. The surface footprint of some of these methods of carbon storage can also be very large. Still, niche opportunities and potential for alternative fuel production may well see novel storage play some role in the future.
An example of CO2 use without permanent removal from the carbon cycle can be found in the RCI Organic Carbon for Assimilation (OCAP) joint venture. ThePernis Refinery delivers roughly 300kt a year of high purity low nitrogen and low sulphur ’waste’ CO2 to about 500 greenhouses in the region. OCAP aspire to expansion to 1Mtpa for greenhouse supply. Although greenhouse use is an early application for CO2 and in the RCI case has helped develop the CO2 pipeline infrastructure, horticulture applications are considered to be a relatively minor source of future CO2 usage when compared with other industrial applications (Global CCS Institute and Parsons Brinckerhoff 2011).
The Institute commissioned a desktop review of publicly available storage guidelines (CO2CRC 2011) which showed that a reasonably comprehensive suite of guidelines has been published, with the preeminent being the CO2WELLS’s CO2QUALSTORE Guideline (DNV 2010). However, there is probably scope for guidelines that centre on the geomechanical impacts, and risks/opportunities and treatments of exploration and development decisions of CO2 storage.