Position paper: Is CO2 storage safe?

CO2 Storage - Is it safe?

Towards large-scale implementation of CCS

Research and Innovation, Position Paper 06 - 2010

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Contact details:

Todd Flach – Todd.Flach@dnv.com Semere Solomon – Semere.Solomon@dnv.com

Summary CO2 geologic storage (CGS) technology is by no means fail-proof or riskfree, but carefully selected and qualified storage sites that are operated according to effective regulatory supervision should be safe. The key will be to apply fit-for-purpose risk management throughout the lifecycle of the storage sites, starting from screening, and continuing through site selection, qualification, injection operations, and, finally, closure.

CGS is a mature technology that has been used at industrial scale at several large sites both onshore and offshore. CGS technology can be applied immediately, at a much larger scale, at tens to hundreds of sites globally. The main evidence for this is empirical, collected through relevant analogue subsurface industrial experiences and at large-scale demonstrations of CGS at several sites. This includes almost 100 years of natural gas storage at hundreds of sites in North America and Europe, 35+ years of experience with CO2 enhanced oil recovery (EOR) in North America, 15+ years experience with acid gas (mixtures of H2S and CO2) injection in western Canada, and 14+ years experience at dedicated CGS projects in the North Sea and Algeria. Moreover, there are currently a handful of research-focused pilot CGS projects on 5 continents.

The current state of CO2 injection technology can best be summarized by the conclusions reached by the Massachusetts Institute of Technology in their Environmental Assessment of Geological Storage of CO2, namely that: “The technologies and practices associated with geological CO2 storage are all in current commercial operation, and have been so for a decade to several decades...

No major “breakthrough” technological innovations appear to be required for large scale CO2 transportation and storage.”

Introduction CO2 SUBSURFACE INJECTION started in West Texas in 1972 at industrial scale with the dawn of the modern CO2 enhanced oil recovery (EOR) industry. CO2 EOR has been applied at over 200 sites and has already injected a total of over 600 million tons of CO2, using over 10 thousand wellbores (Meyer, 2007). The purpose of this CO2 injection is not reduction of CO2 emissions, but rather commercial production of oil. In fact, much of the injected CO2 is actually produced from natural subsurface CO2 reservoirs, where CO2 has been stored naturally for tens of millions of years. This experience is nonetheless directly relevant for CO2 geologic storage (CGS) for the purpose of reducing anthropogenic CO2 emissions from industrial installations, a technology strategy commonly called CO2 Capture and Storage (“CCS” which includes CGS).

For seasonal storage of natural gas, which started as a commercial industry in the early 1900s (currently operated at over 400 sites worldwide), success depends on careful site selection to achieve storage capacity, and on wellbore engineering to achieve required gas injection and production capacity, while minimizing the risk of losing valuable stored gas through leaky wellbores or other leak paths. Fit-for-purpose monitoring is applied to warn of leaks and to indicate the future capability of the storage site to re-fill and re-produce the natural gas.

The topics of CCS and CGS were comprehensively covered in a special IPCC report (2005), and this reference continues to be a highly relevant and independent source of information on these subjects today.

Acid gas injection operations represent a commercial analogue for some aspects of geological CO2 storage.

Currently, acid gas is injected into 51 different formations at 44 different locations across the provinces of Alberta

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and British Columbia, with no detectable leakage. Carbon dioxide often represents the largest component of the injected acid gas stream, in many cases being 14–98 % of the total volume (IPCC, 2005). Some failed sites are, however, noted in the public record. Of these, three sites were suspended by the regulatory agency because of reservoir over-pressuring.

Several CO2 storage projects are now in operation and being carefully monitored. So far there has been no report of significant leakage of stored CO2 out of the storage formations in any of the current projects. Most of the actual or planned commercial projects are associated with major gas production facilities that have gas streams containing CO2 in the range of 4–15 % by volume, such as Sleipner in the North Sea, Snøhvit in the Barents Sea, In Salah in Algeria, and Gorgon in Australia.

In gas storage operations in USA there have been nine documented incidents of significant leakage: five were related to wellbore integrity, each of which was resolved by reworking the wells; three arose from leaks in cap rocks, two of which were remediated and one of which led to project abandonment. The final incident involved early project abandonment owing to poor site selection (Perry, 2005). These observations emphasize the significance of proper site selection and qualification, and the importance of monitoring for leak detection and storage integrity.

Special Case of Wellbore Sealing The key strategy for avoiding any undesired future movement of stored CO2 is to choose those underground formation locations that are best suited for the task of long-term storage for the quantities required. Such sites will have a set of specific geologic features that must be mapped and verified in order to qualify for long-term storage. Early, coarse screening studies of subsurface resources have been performed in Europe1 and North America2 since 2001. The initial impression is that 100s of times more pore space to store CO2 exists in the underground than the annual emissions from the world’s current power plants and other stationary sources. Most of this pore space consists of deep (>900 meters below surface) saline formations, and unfortunately these have no direct a priori indication that they have trapped fluids over geologic time. Herein is the first special challenge of CGS. There is a key distinction between CO2 storage site selection and exploring for oil and gas reservoirs. In the latter, a sealing system is proven where hydrocarbons (which are buoyant relative to the background saline formation water, and thus tend to migrate upwards unless stopped) are found to be trapped in an underground formation. Such proof will not exist for deep saline formations, and a case for their suitability for long-term storage of CO2 must be established by applying a more comprehensive process of site data collection, interpretation, analysis, and modelling of future performance of the site.

1 For Europe see http://www.geology.cz/geocapacity.

2 For the United States see http://www.netl.doe.gov/publications/ press/2007/07016-Carbon_Sequestration_Atlas_Publish.html

There are three other special aspects concerning CGS qualification. These are: • Every potential storage site is unique; • Subsurface formations are inherently difficult to characterize completely due to the high cost and effort associated with drilling wellbores and collecting site data; • Geoscience-based technology and reservoir engineering are still evolving and improving rapidly Thus, the starting point for establishing confidence in CGS contrasts sharply with traditional engineered systems that can be completely visualized and described in comprehensive, detailed simulation models.

Each site is unique and most are data-sparse A potential CGS site will always be data-sparse (with the possible exception of depleted hydrocarbon reservoirs used for CGS) and a large degree of irreducible subsurface uncertainty will be unavoidable. Despite this, a significant number of high-quality CGS sites are known to exist and we are confident that they can be effectively identified and qualified for their planned use. Given the special challenges outlined above, it is clear that no single, standardized qualification prescription will ever exist for the vast varieties of sites and constantly evolving set of technologies. The solution would therefore appear to be a repeatable work flow that is flexible for the unique profile of each candidate storage site and that evolves as knowledge grows and technologies improve.

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The Solution: Standardized but Flexible Work Flow and Tools CO2QUALSTORE is a guideline for CGS site and project selection and qualification developed by DNV in collaboration with industry partners, the International Energy Agency (IEA) Greenhouse Gas R&D Programme, and representatives from Norwegian authorities as part of a joint industry project.

• assess with a reasonable level of certainty if a storage site is eligible for a storage permit.

The guideline reflects the current understanding of best industry practice and aims to promote consensus among project developers and regulators on proper site selection, qualification, and management. The guideline recognises that this must be tailored to the unique characteristics of any site. In particular, that site selection and management aim to demonstrate that any inherent (natural) or engineered risks or uncertainties are adequately controlled and managed.

The guideline is structured according to the chronological progress and work flow of a generic CGS site development, as illustrated in Figure 1. The aim is to provide a structured and transparent approach to decision making that documents the basis for granting a storage permit to a given project. This includes describing the activities and deliverables necessary to: • gain sufficient knowledge to meet thresholds to select storage sites among a list of potential candidates; • enhance the level of site knowledge through data acquisition, analysis, and risk assessments to a state that provides a basis for management decisions at key project milestones;

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Figure 1. CGS project lifecycle and associated qualification statements, relevant permits, and project milestones.

This process also lays the groundwork for renewing a storage permit and obtaining a site final closure permit.

Such a permit would form the basis for a regulatory authority to accept liability for a storage site from a commercial operating entity.

A number of commercially available, geoscience-based tools already exist that can be directly applied in CGS site qualification and operational management. Some gaps remain, and DNV is working actively to fill them. In particular, simplified calculations appropriate for large numbers of data-sparse candidate sites would be useful for screening entire regions, so that the most promising sites are prioritized. Such site-screening tools range from simple to advanced, and include storage capacity estimation with uncertainty, CO2 plume extent prediction, leakage modelling through abandoned wellbores, most or all of which can be integrated into a Geographical Information System (GIS) platform.

Storage capacity uncertainty estimates and CO2 plume development predictions are central in the site selection stage and for success of a CGS project. Figure 2a illustrates an output of the storage capacity estimation tool using a Monte Carlo Simulation (MCS) showing the estimates as cumulative distribution function (CDF) and the associated uncertainties or confidence levels. Figure 2b demonstrates the MCS results of the iso-probability lines that the CO2 plume hits an abandoned well or fault if the site is characterized by either of these features.

(a)

(b)

Figure 2. Illustrations of Monte Carlo Simulation-based probabilistic tools applicable to site selection and management stage (a) storage capacity estimation, and (b) CO2 plume prediction with uncertainty contour intervals (100 % certainty that the plume will be within the “1 “contour)

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Special Case of Wellbore Sealing Final sealing of a wellbore after it is no longer used was a technical and regulatory challenge in the industry up until about 1960 (Nicot, 2008). Clearly any candidate CGS site must be evaluated in terms of the potential risk of leakage up any older, abandoned (legacy) wellbores within its boundaries. Abandoned wellbores are widely spread in all regions, but especially where oil and gas exploration and production activities are in practice. For example, in the Alberta Basin in western Canada, more than 350,000 wells have been drilled. The state of Texas has several hundred thousand abandoned wellbores, but the exact number is not known because official wellbore records are relatively sparse up to the 1930s. Wellbores are generally distributed spatially in clusters around oil and gas discoveries, with regional densities of 2-4 wells per km2 (Gasda et al., 2004, Nicot 2008) in hydrocarbon-rich provinces.

It appears that it is generally likely that leakage will occur from the deep sections of older wellbores to shallower formations (Nicot, 2008). There are a number of reasons for this, but most are related to limited technology for cement and sealing up until the 1950s, and lack of regulatory mandate and capacity up until the 1970-80s, depending on the region, and variations in quality control in field operations through time and across organizations.

All of these problems are essentially solved for all future wellbore sealing and abandonment cases. It is the legacy wellbore cases that form the bulk of leakage risks for potential CGS sites.

Alberta Province in Canada is one of the most studied regions with respect to leakage potential from abandoned wellbores (Bachu and Watson, 2006; Watson and Bachu, 2007 and 2008). The general conclusion of these papers is that a range of 12 easily defined wellbore attributes are

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enough to identify the abandoned wellbores at greatest risk of future leakage. This methodology is preferred when handling thousands of wells, and the initial task is to rank and prioritize the limited and expensive resources for remedial wellbore entry.

Although this approach is adequate to address historical wellbore leakage problems, it is insufficient for preventing similar problems in future CO2 service wellbores. The causes of leaky wellbores are generally understood, but it was only after CGS research and development began in earnest that the physics of leak initiation and propagation were systematically studied (Gasda et al., 2004) in the context of corrosive attack from CO2-saturated reservoir brine. Vastly improved cement types, cementing procedures, and final wellbore sealing solutions will come to market in the near future.

When will a wellbore leak Although leakage through abandoned wellbores is likely if current standard practices are applied, a combination of CGS fit-for-purpose data, tools, and knowledgebase can these manage risks.

DNV has developed a systematic approach for screening abandoned wellbores by employing the reliability method (RM) in combination with a database system using a spreadsheet or dBase, or using GIS. This database (e.g. those used by Watson and Bachu, 2007) serves as input to the RM by selecting parameters/fields of interest for the determination of the probability of failure. An interface with the GIS will allow analysis of the data in a

spatial context, thereby providing a platform for risk-based decision making. In addition, it will serve as a decision gate for a detailed modelling at critical zones such as degradation or corrosion or geomechanical and flow simulations. Moreover, it will provide input to the design of monitoring network systems as well as selection of sites for environmental impact assessment studies.

Figure 3a shows the analytical solution of the pressure buildup at the locations of the abandoned wells for a series of CO2 injection scenarios (10 to 50 years). As expected, the maximum pressure build-up is close to the injection well, and decreases away from the injection centre. Leakage rates at abandoned well locations are a function of time (arrival times), as presented in Figure 3b, and depend on various factors, including, among others, pressure buildup. CO2 flux in leaky wells rises sharply when the CO2 reaches the wells, and continues to increase afterwards due to the continued pressure build-up in the system. The wellbore leakage model also estimates the time at which CO2 reaches the abandoned wells; for instance, CO2 will reach a well located at 100 m from the injector after a short time interval (about 1.5 days), but will arrive at one at 5000 m after about 900 days. Given the reservoir conditions, the arrival times of CO2 at abandoned well locations can be estimated.

the probability of failure increases as the well’s intrinsic permeability increases, and, for a given well location, the probability of failure decreases with increasing threshold leakage rate value.

A more advanced modelling of abandoned wellbore risk has also been developed using the Bayesian Network method (Figure 4). The model illustrates how to consistently integrate leakage probability and the potential consequences of a failed abandoned wellbore at a CO2 storage site, in which stored CO2 is released from geological storage. The abandoned wellbores were secure before the start of the CO2 injection phase. Human/ natural interference with the capping design (the plugs of the abandoned wellbore), together with degradation and pressure build-up due to continuous CO2 injection, resulted in the failure occurring. The model depicts the consequences of CO2 leakage, both to the atmosphere and to a freshwater aquifer, in terms of monetary values (losses).

A more detailed analysis of this model is presented as a CCS case study in the IntegRisk EU Project and is available via Friis-Hansen et al (2010).

The likelihood of containment failure at a storage site is assessed by considering a set of wells at specified locations, relative to the injection well. The probability of occurrence of leakage at wells located far from the injection well is usually less than that from those lying close, especially those near the injection zone (Figure 3c). Figure 3d shows the impact of different intrinsic well permeability values (kw = 10, 100, and 1000 milliDarcy) on the probability of failure in the abandoned wellbores. For a given leakage threshold,

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(a)

(b)

(c)

(d)

Figure 3. Typical model results derived using DNV’s approach for abandoned wellbore integrity analysis: (a) Pressure build-ups at abandoned wells for various Injection Periods (IP); (b) Normalized, dimensionless leakage rates (leak rate/injection rate); (c) Probability of containment failure; and (d) Impact of well permeability, i.e. kw in milliDarcies.

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Risk Analysis

Figure 4. Risk analysis using a Bayesian Network model for leakage from an abandoned wellbore.

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Fit-for-purpose Site Monitoring “Watching the Stable Door” Simply put: if you know that the stable door has stayed shut, then the horse has not left the barn. Just watch the stable door! For CGS sites, “watching the stable doors” means that the initial mapping process indicates those paths that are most likely to be followed, should stored CO2 leave the storage formation, and therefore any monitoring should focus on these paths. This could also be referred to as “risk-based monitoring” because monitoring is focused on high probability places (as a first approximation, the consequences of potential leakage are taken as being the same at all locations). Lack of any evidence of movement of CO2 out of the storage formation through these monitored paths is a very positive indicator that storage at the site is successful. In other words, lack of any evidence that CO2 is moving out of the storage complex, despite diligent, fit-for-purpose monitoring, is de facto evidence that the storage site is not leaking. To repeat, the key to risk-based monitoring is a comprehensive mapping of the storage site with respect to potential leak paths. This mapping must also be updated as site data and understanding grows and improves.

Regarding monitoring of the surface, special CO2 sensors have been developed that can cover a large area, and can detect any CO2 anomalies (concentrations exceeding the normal limits of otherwise variable background values) in the air space a few meters above the soil.

The final “stable door” to monitor are shallow aquifer (water) zones and the surface. Shallow aquifer monitoring wells are used on all continents to monitor ground water levels and quality trends with respect to contaminant seepage from a variety of sources. These are very cost effective and would reveal any CO2 intrusion into a shallow groundwater formation that might be caused by leakage from a deep saline aquifer storage project.

Figure 5. One “stable door” that is commonly watched, is the water quality of shallow aquifers that lie above the target CO2 storage reservoir.

An indication of CO2 or brine intrusion into the shallow aquifer, as detected in samples from a monitoring or observation well, would trigger further action to check for leakage. This monitoring formation is often called an “indicator zone”.

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“Bottoms-up Verification” The ultimate strategy for building confidence in storage performance is to observe and visualize the actual subsurface “cloud” or “plume” of CO2 in the target formation and to estimate its mass. The latter can be achieved using calculations based on the raw monitoring signals and geoscience principals related to seismic signal interpretation, petrophysics, electro-tomography relationships, and geomechanical modelling. This is often referred to as “bottoms-up” verification, because the mass of the CO2 calculated to be in the reservoir is based on measurements and monitoring of the CO2 “at the bottom,” i.e. in the reservoir. This can then be compared with the known injected mass of CO2 measured at the surface, for which uncertainty is less than 2 %. Any significant deviation between the surface injection mass and the mass estimated in the target storage formation would constitute “non-conformity” and would trigger further investigation.

The Sleipner project has followed the “bottoms up verification” strategy. Sleipner has been the world’s largest CO2 storage project in a deep saline formation (Utsira) since 1996, and has injected ca. 14 million tons CO2 up to the end of 2010. A series of research projects associated with the Sleipner CO2 storage operations have produced a number of unique results, especially regarding “bottomsup verification” of stored CO2 (Bickle, et al., 2007). The CO2 stored in the Utsira formation has been imaged using repeat seismic surveys in 1999, 2001, 2002, 2006 and 2008.

The seismic images have been used to produce estimates, with associated uncertainties, of the total mass of the injected CO2. These have been compared with known (uncertainty <2 %) injection masses from fiscal metering on the injection platform.

A major uncertainty in estimating the in situ mass of stored CO2 is the reservoir temperature. Uncertainty in Utsira reservoir temperature is as high as 3 °C, which for the reservoir pressure of the Utsira implies an uncertainty in CO2 density in the reservoir of 6-8 %. Other significant uncertainties include the seismic (acoustic) properties of the reservoir layers, as well as the acoustic properties of different mixtures of reservoir brine and CO2.

Nordland claystone and quaternary silt

˜ 700-800 meters thick

Utsira sand

Thin, discontinuous mudstones

CO2 injection well

Hordaland claystone Figure 6. Schematic cross-section of CO2 injection in the Utsira formation at Sleipner (figure inspired by Bickle, et al., 2007). CO2 rises buoyantly and is trapped successively beneath thin mudstones before reaching the cap rock (Nordland shale).

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Consequences of Leaky Storage Sites The most important generic containment failure modes in CO2 storage sites have been identified (Benson, 2004) and include: • Leakage through poor quality or aging injection well completions • Leakage up abandoned wells • Leakage due to inadequate cap rock characterization • Inconsistent or inadequate monitoring According to Keith and Wilson (2002), the potential consequences of leakage from CGS sites fall into two categories: (1) local environmental risks, and (2) global risks arising from leaks that return stored CO2 to the atmosphere.

Global risks may alternatively be viewed as uncertainty in the effectiveness of CO2 containment. Local health, safety, and environmental risks arise from three processes: • the elevated CO2 concentrations associated with the flux of CO2 through the shallow subsurface to the atmosphere; • the chemical effects of dissolved CO2 in the subsurface; and • effects that arise from the displacement of fluids by the injected CO2.

The most important local risks could arise from elevated concentrations of CO2 in near-surface soils and in the atmosphere, where exposed people or animals could be asphyxiated, and local biota damaged (effects on plants above ground and below ground, on roots, insects and burrowing animals). Leaked CO2 that dissolves in subsurface fluids may mobilize metals or other

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contaminants, and degrade drinking water. In some rare cases, where the reservoir fluid pressure increases significantly in the storage formation, there may be some subtle ground heave or an occasional event with induced seismic noise. Displacement of fluids by the injected CO2 may degrade shallow subsurface drinking water by displaced brines.

The most obvious local risk is catastrophic leaks, such as well blowouts, pipeline ruptures, or subsurface events that result in sudden releases of CO2. Catastrophic events can also be caused by slow leaks from deep CO2 reservoirs if the CO2 is temporarily confined in the near- surface environment and then suddenly released. As CO2 is denser than air, it flows downhill and can create asphyxiating conditions near ground level in local low spots in the topography, far from the initial release site.

While catastrophic releases attract the most attention, slow leaks may pose risks that are more difficult to manage.

Biological impacts in the shallow subsurface must be evaluated, recognizing possible detrimental effects on flora and fauna, particularly burrowing fauna. Because surface air is far better ventilated than soils, it may well be that significant biological impacts, such as tree kills due to CO2 in the shallow subsurface, may occur at CO2 fluxes smaller than those required to produce appreciable harm to above-ground organisms.

Slow leaks of natural CO2 are known to cause impacts. A leak of ~100 t CO2/day at Horseshoe Lake in California has killed many hectares of trees. Slow leaks of CO2 from shallow coal beds in Saskatchewan, where CO2 has built up in confined areas such as old pits and adits, have also caused fatalities.

The global risks stem from the release of stored CO2 into the atmosphere or ocean, leading to increased ocean acidity and accelerated global warming. Due to the energy penalties involved in CO2 capture and storage, more CO2 will be produced per unit of delivered energy using capture and storage than would have been emitted if the fossil fuels had been used without capture. In the worst case, therefore, a failed storage system can increase CO2 emissions compared with not applying CCS. Assuming very large volumes of CO2 are stored in the subsurface in the future, even small leakage rates could result in significant amounts of CO2 leaking into the atmosphere. In the near term, however, with comparatively small amounts of CO2 stored, small leak rates pose a challenge for accounting but will not have a significant global effect.

Natural CO2 Seeps Shed Light on Risks CO2-charged cold geysers are extremely rare, and Crystal Geyser in south-eastern Utah is the largest cold geyser in the world. This geyser was unintentionally created in 1936 after a prospective oil well was drilled about 800 m deep into a fault zone above a natural CO2 reservoir. Shortly after drilling, this well was abandoned and not properly completed or plugged. Now, it erupts dramatically every 4-24 hours due to CO2 charging (Bogen et al 2006).

Locals and tourists are frequent visitors to the well and there are no documented occurrences of ill effects.

Measured average concentrations of CO2 close to the geyser never exceeded 12,500 ppm (1.2 %) and typically are around 6000 ppm (0.6 %). These levels are well below the limits of 4-5 % at which acute human health effects are documented, and far below the 15 % levels that result in rapid loss of consciousness and the 30 % levels of CO2 that cause immediate death (Benson et al 2002).

While the Crystal Geyser example suggests the emissions rates and health risks associated even with long-term catastrophic failure of a single well may typically be low, meteorological and/or topographic (MT) conditions can conspire such that CO2 accumulates to lethal levels. While the Lake Nyos natural disaster in Cameroon in 1986 is the worldâ&#x20AC;&#x2122;s most horrific example of a natural CO2 release, involving both a large source term and unfavourable conditions, much smaller source terms can also lead to fatalities under certain conditions. One such scenario was played out at Mammoth Hot Springs, where 3 ski patrol members died after falling into a CO2-filled ice cave created by a volcanic fumarole (Riley 2006). In this case, the physical topography was altered by deep snow in which fumarole gas melted a cavity that filled with lethal levels of CO2. An unmapped, abandoned well leaking at a CO2 storage site could create a similar potential wintertime hazard.

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Natural seeps are widely distributed in tectonically active regions of the world (Morner and Etiope, 2002).

In central Italy, for example, CO2 is emitted from vents, surface degassing, and diffuse emission from CO2-rich groundwater. CO2 fluxes from vents range from less than 100 tCO2 day–1 to more than 430 tCO2 day–1; levels which have been shown to be lethal to animals and plants. At Poggio dell’Ulivo, for example, a flux of 200 tCO2 day–1 is emitted from diffuse soil degassing. At least ten people have died from CO2 releases in the region of Lazio over the last 20 years (IPCC 2005).

Proper site selection, combined with well designed monitoring strategies, contributes to managing the risks related to a potentially leaky CO2 storage sites.

CO2QUALSTORE guideline is the first of its kind to provide a transparent approach to managing the risks in CGS that will allow confidence building for all the stakeholders involved.

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Remediation of Storage Sites Reservoir simulation can be used to study proposed mitigation strategies in cases where reservoir over-pressure is considered to constrain injection volumes and/or CO2 seepage poses a hazard. Verification of such model simulations will be important for local health and safety in the short- to medium-term, and for global greenhouse gas emissions in the medium- to long-term.

After 500 years of simulated storage, the following observations can be made:

A variety of remediation options are discussed in a special report commissioned by the IEA GHG R&D Programme (Kuuskraa and Godec 2007). The method demonstrated here involved the production of brine from the primary storage formation and reinjection of produced brine into a shallow aquifer formation.

b) Brine production takes place from the base of the target aquifer, 5 km distant from the CO2 injection point. The pressure differential between the two aquifers is thus reduced and the CO2 plume has not yet reached the top of the shallow aquifer.

Test simulations were performed for two seepage mitigation scenarios that involved production of brine from the target aquifer (Figure 7b) and, in addition, re-injection of brine into the shallow aquifer (Figure 7c). These two simulations are intended to represent two generic cases that can be instructive for verification of seepage mitigation simulations. Figure 7 shows the effectiveness of the two seepage mitigation measures with respect to the base case 2-aquifer model, Model a. All three snap shots of the plume development are taken at 500 years after the start of injection, and the mitigation measures were in place from six years after the start of injection until the end of injection at 40 years.

c) Brine produced in scenario b) is re-injected into the base of the shallow aquifer above the point of brine production. 50 % of the brine produced is reinjected and the pressure differential between the aquifers is further reduced. The CO2 plume has not yet penetrated the fracture in the cap rock and remains isolated from the shallow aquifer.

a) Base case model; the CO2 has penetrated the fracture in the cap rock and reached the top of the shallow aquifer where it has begun to pool.

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(a)

(b)

(c)

Figure 7. CO2 molality at 500 years with a) no mitigation, b) production of brine five km from the CO2 injection point, c) production of brine five km from the CO2 injection point with 50% reinjection at the top of the â&#x20AC;&#x153;leakâ&#x20AC;?

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Broader Application of CGS Beyond Fossil Fuels Currently, the overwhelming focus of CGS is on projects that are intended to reduce CO2 emissions from large, fixed, fossil fuel-based production plants (electric power, cement, steel, petrochemicals, etc.). A common criticism of CGS is that, in this context, it is a strategy to prolong the use of fossil fuels and to delay the introduction of more sustainable energy and production technologies.

In a climate change scenario, in which positive feedback dominates the atmospheric composition, complete elimination of anthropogenic emissions may not stop a continual increase in GHG content due to out-gassing of methane from permafrost, soils, etc.

This has motivated research to evaluate the potential of CGS contributing to decreasing atmospheric GHG content, even when all fossil fuel use has been replaced, or when that remaining has CCS retrofitted. The technology strategy is to apply CGS to CCS projects based on biomass or direct capture from air. Already there is a very large ethanol production capacity in North and South America, based on biomass fermentation. Bio-ethanol production plants emit considerable amounts of CO2 from the key fermentation process unit, i.e. the large fermentation tanks. These perform several functions, one of which is to vent the gases from fermentation (CO2 and water vapour) safely. Separating CO2 from this mixture is a simple matter, in which the fermentation tank off-gases are cooled, thereby condensing the water vapour. The near-pure CO2 can then be compressed and permanently disposed of by using CGS.

the CO2 from the boiler emissions, just as in a fossil fuel combustion facility. The carbon from the biomass would then be effectively moved from the biomass/atmosphere to the underground where it would be permanently stored. The result would be a net reduction of CO2 from the atmosphere, as opposed to a near-neutral CO2 emission effect from CCS applied to a fossil fuel plant.

Biomass also has the potential to be gasified and a process could be applied in a similar way as to that which is being studied for pre-combustion CO2 capture in the Integrated Gasification Combined Cycle (IGCC) process.

And finally, this document must include one mention of the â&#x20AC;&#x153;holy grailâ&#x20AC;? of CCS, namely, direct capture of CO2 from air and its permanent disposal using CGS. This concept is under intense study at the University of Calgary (Keith et al, 2010), the Swiss Federal Institute of Technology (Nikulshina et al, 2006), and Columbia University (Lackner et al., 2001). The strategy of direct capture from air allows the capture plant to be located on the surface, directly above the underground storage site, thereby avoiding the expense and risk of long-distance, high-pressure CO2 pipelines.

These techniques, together with CGS, could continue to contribute to reducing the atmospheric content of CO2, even after fossil fuels have been completely replaced, or when CCS is implemented in all fixed, remaining fossil fuel plants.

Biomass can also be combusted to heat a steam boiler and generate electricity and process heat. A traditional postcombustion scrubber system (using amines or chilled ammonia, or some other chemical absorber) could remove

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Conclusions All the important risks for CGS projects have been identified, and the R&D community and industry have found solutions to most, if not all, of these. Because every storage site will be unique, each site will need to be individually qualified, based on its own specific profile of subsurface and surface properties, and using the best available technology and solutions as they inevitably evolve and improve. Standardized work flows that promote sitespecific qualification will make this task more effective, while avoiding the traps of prescriptive, static, technical solutions. The key features of site qualification will be transparency and complete, auditable records of the permit approval process, such that public confidence can be earned and maintained.

Very similar industrial activities in the EOR industry, injecting CO2 in large quantities (cumulative injection ca.

600 million tons CO2) in the underground to increase oil production, have generated high confidence in key parts of the systems required for CGS in deep saline formations for the purpose of reducing GHG emissions. Indeed, permanent disposal of gases by injecting them into the subsurface has been practiced for over 15 years in Canada, and CO2 permanent storage by injecting large volumes into a deep saline formation has been practiced at Sleipner since 1996. These projects have shown that although the CGS strategy is neither failure-free nor totally without risk, industry and regulators have the necessary solutions to manage risks effectively.

Nonetheless, scale up of this strategy, from the current situation of a few projects to hundreds of projects, remains a challenge. DNV is actively developing and promoting compact, standardized evaluation tools for the site screening phase and that have the potential to be applied to screening thousands of candidate sites, so that they can

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be ranked according to a relatively sparse, but indicative, set of site characteristics.

Once candidate sites have been selected for more detailed exploration and site surveying, a set of more advanced and detailed evaluation processes will potentially lead to application for a storage permit. Fit-for-purpose regulatory capacity and frameworks are being developed and will be fully operational in the near future.

Proper site performance will be verifiable for sites that have carefully designed and installed fit-for-purpose monitoring systems that follow the evolution of the site throughout its lifecycle. DNV anticipates a growing need for independent verification of monitoring systems and data to maintain public confidence in site integrity.

Although final site closure is a challenge that is still 20 years away, the entire community of CGS stakeholders is actively preparing for this phase. Much of the experience from sealing and abandoning wellbores in the oil and gas industry will be directly applicable.

CO2 geologic storage can be made very safe, given that the main safety barrier is a kilometer (or more) of the Earthâ&#x20AC;&#x2122;s crust, and that subsurface geoscience and engineering are applied using the most effective risk management methods, originally developed for a range of industrial activities and carefully adapted to fulfil the special needs of CGS.

References Bachu, S., Watson, T.L., 2006. Possible Indicators for CO2 Leakage along Wells. Paper presented at the 8th International Conference on Greenhouse Gas Control Technologies, June 19-22, Trondheim, Norway. CD ROM, Elsevier.

Dai, Jianjun, Arvinder, Singh, Kenton, Heidel, Keith, David.

(2010). “Process Simulation of Direct CO2 Capture from Air: Mass and Energy Balance, Unit Operations” Poster at GHGT-10, Amsterdam, The Netherlands, September 21, 2010.

Benson, S.M., R. Hepple, J. Apps, C.F Tsang, and M. Lippmann. Lessons Learned from Natural and Industrial Analogues for Storage of Carbon Dioxide in Deep Geological Formations, LBNL-51170. Berkeley: Lawrence Berkeley National Laboratory; 2002.

Flach T., Carpenter M.E., Solomon S.F.; Integrated Reservoir Simulation of CO2 Geologic Storage: Generic Leak Paths and Mitigation Strategies. Conference/ meeting: The 4th Trondheim Conference on CO2 Capture, Transport and Storage 2007-10-16

Benson, S.M. Challenges in CO2 Capture and Storage: Emphasis on Storage in Geologic Formations. Lawrence Berkeley National Laboratory Berkeley, California 94720.

Third Annual National Energy Technology Laboratory Sequestration ConferenceMay 4, 2004

Friis-Hansen, P et al. 2010. Emerging Risks - Related Policies. SP1: Establishing the basis for the European Integrated approach to emerging risks: ERRAs – Emerging Risk Representative Industrial Applications. European Virtual Institute for Integrated Risk Management-EU-VRi.

Bickle, Mike, Chadwick, A., Huppert, H., Hallworth, M., Lyle, S. “Modelling Carbon Dioxide Accumulation at Sleipner: Implications for Underground Carbon Storage.”

Earth and Planetary Science Letters 255 (2007) 164–176.

Downloaded from online site.

Gasda, S.E., S. Bachu and M.A. Celia, 2004: The potential for CO2 leakage from storage sites in geological media: analysis of well distribution in mature sedimentary basins.

Environmental Geology, 46(6–7), 707–720.

Bogen K., et al. Source terms for CO2 risk modelling and GIS/simulation based tools for risk characterization. in Proceedings of the 8th International Conference on Greenhouse Gas Control Technologies (GHGT-8). 2006.

June 2006,Trondheim, Norway.

Clarke T. Taming Africa’s Killer Lake. Nature, 409, pp. 554– 555 (2001).

IPCC, 2005: IPCC Special Report on Carbon Dioxide Capture and Storage. Prepared by Working Group III of the Intergovernmental Panel on Climate Change [Metz, B., O. Davidson, H. C. de Coninck, M. Loos, and L. A. Meyer (Eds.)]. Cambridge University Press, Cambridge, United Kingdom and New York, NY, USA, 442 pp.

Keith D. and Wilson M. 2002. Developing Recommendations for The Management Of Geologic Storage Of CO2 In Canada.

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Kuuskraa, V. A. and M. L. Godec (2007). Remediation of leakage from CO2 storage reservoirs, Advanced Resources International.

Meyer, James P. (2007) Summary of Carbon Dioxide Enhanced Oil Recovery (CO2EOR) Injection Well Technology. Supporting Information Provided by PhD, Contek Solutions, 2007. 2828 West Parker Rd., Suite 102-B. Plano, Texas 75075. Prepared for the American Petroleum Institute in 2007.

Morner, N.A. and G. Etiope, 2002: Carbon degassing from the lithosphere. Global and Planetary Change, 33, 185–203.

Nicot, J.P. 2008. A survey of oil and gas wells in the Texas Gulf Coast, USA, and implications for geological sequestration of CO2. Environmental Geology, 57(7): 16251638.

Perry, K. F. (2005). Natural gas storage industry experience and technology: Potential application to CO2 geological storage, Carbon Dioxide Capture for Storage in Deep Geologic Formations—Results from the CO2 Capture Project, v. 2: Geologic Storage of Carbon Dioxide with Monitoring and Verification, S.M. Benson (ed.), Elsevier Science, London, pp. 815–826.

Riley, B. Three ski patrollers die in fall into volcanic vent at Mammoth. Associated Press. Friday, April 7, 2006. http://www.sfgate.com/cgibin/article.cgi?f=/news/ archive/2006/04/06/state/n165002D73.DTL Solomon S. and Flach T. 2010. Carbon Dioxide (CO2) Injection Processes and Technology.(edt. Maroto-Valer M.), In: Developments and Innovation in Carbon Dioxide (CO2) Capture and Storage Technology, Volume 1, Chapter 14.

Woodhead Publishing. ISBN 978-1-84569-515-6.

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Solomon, S., Flach, T., Carpenter, M.E.; “Intermediate Storage of Carbon Dioxide in Geological Formations: A technical perspective”, International Journal of Greenhouse Gas Control, 2008(2):502-510.

Solomon S and Haug L.T. 2009. Framework Methodology for Wellbore Integrity Assessment In Producing Wells. DNV Technical Report NO BRINO912SEMSO091126-1, 29p.

Solomon S., Gravir G., Flach T., Friis-Hansen P. and Tvedt L. 2009. A Prototype For Abandoned Well Leakage Evaluation Tool: Deliverable AWLET Phase I. DNV Technical Report NO BRINO912SEMSO091014-1, 39p.

Solomon S., Flach T.; Estimating Failure Probability From Co2 Geological Storage: CLIMIT-SP5 Report, Høvik 200812-15, DNV Report no.: BRINO912081215-1 Solomon S, Flach T., Gravir G., Ronold K.O., Hagen Ø., Stoffel A., Rygh L.S., Haug L.T., Tvedt L.; Abandoned Well Leakage Evaluation Tool, Høvik 2008-12-15. DNV Report no.: BRINO912SEMSO081202-1 Solomon, S., Flach, T., Carpenter, M.E.; Discrete leak path ways detection methodology - CLIMIT SP1 Report, Høvik 2007.12.21, Report no. BRINO912SEMSO080116-3 Solomon S., Flach T., Carpenter, M. and Selmer-Olsen, S. "A simplified, semi-analytical method to handle uncertainty in long-term containment in geologic CO2 storage sites", Greenhouse Gas Control Technologies (GHGT-9) Conference in Washington D.C., November 2008.

Watson, T. L. and Bachu, S. 2007. “Evaluation of Potential for Gas and CO2 Leakage along Wellbores” SPE article 106817, presented at the 2007 SPE E&P Environmental and Safety Conference, Galveston, 5-7 March 2007.

Watson, T. L. and Bachu, S. “Identification of Wells with High CO2-Leakage Potential in Mature Oil Fields Developed for CO2-Enhanced Oil Recovery” SPE article 112924, presented at the 2008 SPE/DOE Improved oil Recovery Symposium, Tulsa, Oklahoma, 19-23 April 2008.

See http://www.dnv.com/co2qualstore for project description and deliverables for the Joint Industry Project on developing guidelines for CO2 geologic storage site selection and qualification.

See http://www.geology.cz/geocapacity for a review of storage site capacity surveys in Europe.

See http://www.netl.doe.gov/publications/press/2007/ 07016-Carbon_Sequestration_Atlas_Publish.html for a review of surveys of storage site capacity in USA and parts of Canada.

See http://people.ucalgary.ca/~keith/AirCapture.html for more information on capture of CO2 directly from the atmosphere.

Experiments in CO2 air capture were featured on Discovery Channel’s “Project Earth” series, ‘Fixing Carbon’ episode.

Discovery Project Earth - The Fixing Carbon Scrubber. http://dsc.discovery.com/tv/project-earth/lab-books/ fixing-carbon/scientist.html

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