Ambient air capture technologies: Progress so far

Technology to capture CO2 directly from ambient air has the potential to significantly reduce emissions from non-point sources and to capture historic emissions (Lackner 2009).  Sorbents used in flue gas scrubbing can be used much to the same effect in free standing CO2 capture units, which can be designed to compensate for the lower CO2 concentration in the air stream.  It is important to carefully choose a sorbent material that will maximize capture, and to consider a practical and marketable unit design and size.  Lackner proposes that capture units be made on the scale of capturing one ton of CO2 per day.  Given this, and the energy tradeoff associated with the operation and manufacturing of these units, Lackner determines that it would take approximately ten million capture units to make a significant impact on the world’s CO2 emissions.  At present, prototypes for these units could break even at $200/ton of CO2 captured, but Lackner predicts that over time this price could feasibly drop to $30/ton.  Ambient air capture is at this time technologically feasible, and may in time be economically feasible with the improvement of sorbent materials and as the need for retroactively capturing emissions grows. — Shanna Hoversten   
  Lackner, K., 2009. Capture of carbon dioxide from ambient air. The European Physical Journal 176, 93–106.

 K.S. Lackner from Columbia University presents a comprehensive review of the progress towards implementing ambient air capture units, and focuses more deeply on capture sorbent development.  Lackner discards the notion of using an aqueous sorbent due to the large binding energy required and the corrosiveness of a strong sodium hydroxide solution.  Experiments were thus carried out to identify a sorbent with lower binding energy that could still maintain an uptake rate equal or better to that of a sodium hydroxide solution.  Ultimately a solid strong-base ion-exchange resin was deemed to be the best sorbent option.  Experiments showed that this resin could be loaded with absorbed CO2, and upon exposure to moisture the CO2 would be driven off and the resin would be ready to recommence CO2 uptake after dried.  Based on this, Lackner goes on to describe a modular unit that could be easily deployed and could be expected to capture one ton of CO2 per day. 

Lackner’s summary of ambient air capture technology exposes both the potential for further innovation and development of this technology, and the great promise for this technology to significantly reduce CO2 emissions.  At present, 70% of the cost of the device derives from the development of the resin and the regeneration chamber; a reduction in these costs is essential in order to make the technology viable.  Although changes in the filter thickness can compensate for regional differences in CO2 composition of the air stream, and air flow rate over the filter, current technology excludes the deployment of these modules from locations with extremely cold temperatures or locations with high humidity.  However, in places where the units would work effectively, large air capture parks could be established directly on top of the designated storage site, eliminating the need for transfer networks.  Ambient air capture units would collect CO2 from power plants and transportation sources alike, in addition to capturing past emissions at a rate far exceeding collection rates by trees, thus providing a promising technique for CO2 emission mitigation in the future.  

Steps to implementing an effective CO2 transport system in the European Union

CCS technology will be an important component of the European Union’s strategy to reduce CO2 emissions, however, the E.U. faces a series of challenges to building the necessary pipeline infrastructure to transport CO2 from source to sink (Coleman, 2009).   The first task is to identify source and sink locations and match them based on capacity. CO2 transport will likely occur across national borders, and potentially across regions outside of the E.U., thus there is an imminent need for coordinated administrative and legislative frameworks. The estimated pipeline capacity required is very large—400 million tonnes per year by 2030 to meet the E.U. interim targets for emissions reductions.  Although this network will likely require infrastructure as intensive as the existing infrastructure for natural gas pipelines, it is unlikely to be as physically invasive because the pipelines will carry CO2 from many source locations that will then be tied to large trunk lines that feed into large storage sites.  Because the E.U. is extremely urbanized, there are numerous health and safety concerns that come along with these massive installments.  In his paper, Coleman seeks to describe these transport infrastructure hurdles in detail and outline the way by which they can be resolved. — Shanna Hoversten   
  Coleman, D., 2009. Transport Infrastructure Rationale for Carbon Dioxide Capture & Storage in the European Union to 2050. Energy Procedia 1, 1673–1681. 

 D. Coleman of Shell Future Fuels & CO2 , sought to base his series of recommendations on an investigation into the pattern of emission sources and storage sites across the E.U.  Generally, he found that large population centers contained the majority of large-scale single-source points of CO2 that will ultimately be captured.  Europe has numerous locations that can accommodate CO2 storage, and thus it can be assumed that captured CO2 would only have to be transported 200–250 miles, on average, to its designated storage location.  Coleman went on to preliminarily coordinate point sources and sinks throughout Europe.  
Based on Coleman’s analysis, it is clear that matching sources and sinks will frequently straddle national borders, thus Coleman outlines the need for E.U. wide regulatory standards.  A completely new permitting and safety regime is not necessary, as CO2 transportation can be regulated under many of the same mechanisms existing today for the pipeline transport of natural gas.  However, there are a few distinctions between CO2 and natural gas transport that will need to be considered, including: the need to burry transport pipelines deeper underground to ensure that the pressure is great enough to keep the CO2 at its supercritical phase level, and the addition of crack arrestors to ensure that if a puncture in the line does occur, an uncontained longitudinal explosion will not occur. CO2 pipelines have historically been built in rural areas, and thus in the highly urbanized environment that predominates in the E.U., a reasonable distance between the pipelines and buildings or dwellings must be distinguished.  In addition to these regulatory requirements, the next important consideration is to design the most effective and rational transport network given the location of sources and sinks; for the development of this Coleman recommends a Flagship Programme to kick-start the EU CCS industry implementation. 

Predictions of the efficacy of CCS technology: short-term storage may actually represent a solution

Carbon Capture and Storage’s potential to mitigate global climate change is still widely contested; in this study CCS’s potential benefits are quantified and its efficacy is examined under several different scenarios (Stone et al., 2009).  When estimating the possible benefits of CCS, the most important variables that need to be addressed are the storage retention time of the reservoirs used, the energy penalty of the operation, the extent that CCS technology will be deployed, future emissions scenarios, and the degree of climate sensitivity.  The study finds that CCS technology is worthwhile, and has the potential to make a significant difference curbing rising temperatures, especially in the short term. —Shanna Hoversten    
Stone, E., Lowe, J., Shine, K., 2009. The impact of carbon capture and storage on climate.
Energy & Environmental Science 2, 81-91.

 E.J. Stone and colleagues analyzed the potential benefits of CCS under a variety of circumstances by combining a model of the carbon cycle with a model for CCS storage potential and propensity for leakages.  One of the strengths of this study is that Stone et al. took into account the atmospheric sensitivity to increased CO2, which had previously been ignored in similar models. The study modeled climate change reductions under two IPCC scenarios- the A1F1 which constitutes a fossil fuel intensive world, and the B1 which represents a world driven by clean, resource-efficient technology.  The effects of variable retention times, energy penalties, fractions of fossil fuel emissions released from a single plant, and the fraction of global fossil fuels emissions subject to CCS are then modeled. 
The study by Stone et al. demonstrates that there are considerable benefits to deploying CCS technology, especially in the short term.  It is much easier to achieve a break-even point for shorter time spans than longer time spans due to the small but constant leakage that will occur from the storage site.  Even so, it may be beneficial to apply this technology in the short term while we are still looking for alternative energy sources that do not emit such a high concentration of CO2.  The importance of these short-term measures will also depend on climate sensitivity, as the maximum temperature reduction benefits of CCS will increase with heightened climate sensitivities. 
Retention time was found to have a significantly greater effect on the efficacy of CCS projects than did other factors such as energy penalty.  Even large energy penalties can be tolerated provided that the retention time of the storage site is adequate.  However that does not mean that storage sites should only be considered if they have the ability to store the CO2 for a 10,000 year duration; one of the most interesting findings of this study was that the use of storage reservoirs previously considered to have insufficiently low leakage rates may still have the potential to confer climate benefits.  Storing the CO2 for even a short period of time may allow for stabilization of atmospheric CO2 concentrations which would in turn reduce climate sensitivity and mitigate substantial rises in temperatures. 

Using CO2—EOR project experience to improve the design of injection equipment for CCS

Several decades of experience with CO2—EOR projects provide invaluable lessons about how to conduct CCS operations in a safe and technically sound way (Parker et al., 2009).  Public perception of the safety risks associated with CCS is one of the major hurdles to wide scale deployment of this technology; CO2—EOR projects have stored over 600 million tons of CO2 without any significant safety endangerment events, thus the technologies and procedures employed in CO2—EOR ought to be emulated.  In the CO2—EOR industry, improvements in the design of injection infrastructure can be applied to the design of the standard equipment used in CCS sites.— Shanna Hoversten   
Parker, M., Meyer, J., Meadows, S., 2009. Carbon Dioxide Enhanced Oil Recovery Injection Operations Technologies. Energy Procedia 1, 3141–3148.

 M. E. Parker from ExxonMobil and his partners at Contek Solutions, LLC. and the American Petroleum Institute, provide a synthesis of information on technical design improvements that have been made over years of  CO2—EOR projects.  An important caveat to these recommendations stems from the heightened potential for corrosion that takes place in CO2—EOR projects due to the use of the WAG (water alternating gas) process; because CCS uses CO2 that is essentially in a dry state, there is a smaller incidence for problems with corrosion as compared to CO2—EOR projects.  Thus, Parker et al. proceed to detail recommendations based on CO2—EOR experience while recognizing that these measures are relatively cautious. 
Parker et al. detail specific designs that should be employed to the wellbore and completion equipment to ensure safe injection of CO2.  Wellbore elements include the casing, cement, and casing heads, and the completion includes the packer, tubing, and wellhead valves assembly.  Casing should be made out of carbon steel, which is both economically feasible and technically sound, provided that it is coated in corrosive resistant material.  Tubing strings exposed to wet CO2 can also be subject to corrosion, and thus should be coated with a protective liner of plastic, epoxy, or glass reinforced epoxy.   Cement is important in anchoring the casing to the formation and providing a seal as well as structural stability.  CO2—EOR suggests that Portland cement can be used effectively in spite of some presence of carbonic acid, despite laboratory data suggesting that the carbonic acid will compromise the integrity of the cement.  However, in cases where carbonic acid is a more significant threat, adding materials such as fly ash, silica flour or other resistant materials can mitigate the risk of corrosion. 

To control corrosion that can potentially occur in the completion equipment, wellhead valve trims and wetted parts of packers should be made of stainless steel, nickel, or Monel.  Experiences with injection of supercritical CO2 have demonstrated the need for elastomers and seals resistant to swelling.  Additionally, CO2 as a solvent will dissolve any hydrocarbon based material, therefore Teflon, nylon, and hardened rubber are effective materials for use in packing and sealing elements.   These refinements made in the design of injection equipment for CO2—EOR can be applied to CCS such that these projects are technically safe and reliable.

CO2–EOR projects can help launch CCS technology on a large scale

Economic viability is one of the greatest challenges to the effective deployment of CCS technology on a wide-scale; but by using captured CO2 in Enhanced Oil Recovery (EOR) projects, some of this economic burden may be alleviated (Ferguson et. al, 2009).  EOR projects have been underway since the 1970’s, and entail the injection of CO2 into largely depleted oil wells, whereby the CO2 lowers the oil viscosity and allows this residual oil to be removed from areas where it was once trapped between pore spaces. It is estimated that 87.1 billion additional barrels of oil may become recoverable in the United States with the use of CO2–EOR. The added advantage of this procedure is the storage of injected CO2 in the newly depleted oil field.  Coal burning power plants equipped with CO2 capture technology could sell their CO2 to EOR project operators at a price of approximately $25 to $35 per metric ton, which would offset the cost of generating power with CCS by approximately $17 to $24 per MWh, thereby facilitating a more widespread installation of this technology across America’s power plants.— Shanna Hoversten    
Ferguson, R., Nichols, C., Van Leeuwen, T., Kuuskraa, V., 2009. Storing CO2 with Enhanced Oil Recovery. Energy Procedia 1, 1989–1996.  

 R. C. Ferguson and colleagues at Advanced Resources International and the U.S. Department of Energy, used a base case scenario to model the propensity for coordination between EOR activities and CO2 capture activities.  First they looked at the conventionally recoverable versus the “stranded” crude oil resources in the U.S.; then they further broke this down by estimating what proportion of the stranded reserves could be recovered using EOR.  Ferguson et. al used a base case to evaluate CO2–EOR potential using an oil price of $70 per barrel and a CO2 cost of $45 per metric ton, differentiating between oil that is technically recoverable and oil that is economically recoverable.  Based on these numbers, the amount of CO2 that could be purchased from capture technology equipped power generating plants was calculated, and the potential economic gain of these plants was estimated.  Finally, Ferguson et. al calculated that oil produced by CO2–EOR would be approximately 70% “carbon free” given the trade-off between CO2 sequestered and CO2 released by burning the oil. 
The potential for extensive use of CO2–EOR technology has many positive implications for CCS deployment.  The revenue offsets and the value for carbon abatement could allow for 40% of the new coal-fuelled power capacity built between now and 2030 to install CCS.  In real terms, this means that sales of captured CO2 emissions by power plants build after 2020 would support the installation of 33 additional CCS equipped plants by 2030. CO2–EOR projects provide a considerable “value added” market for the sale of CO2 emissions, thereby defraying some of the costs of installing and operating CCS technology.  Although the CO2 would be used to facilitate the extraction and continued use of oil, a CO2 intensive energy source, the storage of the CO2 within the oil field would help offset some of the oil’s emissions, and even more importantly, using CCS in this economically lucrative industry would help support early market entry of CCS technology in the coal-fuelled power sector, providing a foundation for future emissions reductions.  Additionally, storing CO2 with EOR would help bypass two present legal barriers to geologic sequestration: establishing mineral (pore space) rights, and assigning long-term liability for the injected CO2.  The promotion of CO2–EOR is a promising avenue for advancing the development and deployment of CCS technology. 

Developing CCS Monitoring and Verification technology

Developing effective technology for surface monitoring of CO2 leakage is an instrumental part of ensuring the wide-scale deployment of CCS technology (Madsen et al. 2009). The primary methods used to monitor surface CO2 flux as the gas is released from the soil into the atmosphere include the micrometeorological method and the chamber method.  Although there are many methods that fall under these two broad categories, this paper focuses specifically on the closed-chamber method (a chamber method) and the Eddy Covariance method (a micrometeorological method).  Madsen et al. argue that two new designs for monitoring equipment have made surface monitoring far more effective and reliable. These equipment models are examined; both the LI–8100 Automated Soil CO2 Flux System (closed-chamber method) and the LI–7500 Open Path CO2/H2O Analyzer (Eddy Covariance method).  The study details the advantages of these models and outlines the importance of employing their use in CCS projects so as to build public confidence in the safety of this technology.— Shanna Hoversten
 Madsen, R., Xu, L., Claassen, B., McDermitt, D., 2009. Surface Monitoring Method for Carbon Capture and Storage Projects. Energy Procedia 1, 2161
R. Madsen and colleagues at LI–COR Biosciences, estimate the capacity of this surface monitoring equipment to pick up CO2 fluxes using mathematical models combining elements of the new technology with environmental variables that effect flux measurements.  The paper also provides details on new design features that allow for additional accuracy in flux measurements, such as the LI–8100’s vent design to minimize the effect of wind on the flux data.  The efficacy of this new technology is assessed by looking at its use in the monitoring and verification regimes at several pilot CCS plants around the world. 
In discussions about the closed-chamber method, Madsen et al. identify several key difficulties with getting accurate flux readings.  Maintaining pressure equilibrium between inside the chamber and the ambient air is one of the greatest challenges, and it can be especially problematic under windy conditions. Ensuring good mixing within the chamber is also necessary, but if a fan is installed to do this it can oftentimes alter the pressure equilibrium.  The LI–8100 factors in these concerns by having a unique chamber geometry that allows mixing without a fan, thereby maintaining the pressure equilibrium.  It also has a new feature in which the chambers all open and close automatically and slowly so that fresh ambient air is not pushed into the soil or removed from the soil and thereby distorting the data.
The Eddy Covariance method measures fluxes by taking measurements of the deviation of vertical wind velocity and of an associated scalar from their mean values.  The sensors for Eddy Covariance are usually mounted on a tower and they then measure the average CO2 flux over an integrated area that can extend to an area about 100 times the height of the sensors to the up-wind direction.  For this monitoring technique to be effective, it is necessary that the model can correct for density perturbations caused by sensible heat and latent heat flux, and it must be set up over a relatively large and flat field site.  Both the LI–7500 and the LI–8100 have been used in CCS projects all over the world, and have so far been effective, however there is still a great need to see how these technologies will perform over the long lifespan of a project.  

Predictions of the efficacy of CCS technology: short-term storage may be a solution

The potential of carbon capture and storage to mitigate global climate change is still widely contested; in this study CCS’s potential benefits are quantified and its efficacy is examined under several different scenarios (Stone et al. 2009).  When estimating the possible benefits of CCS, the most important variables that need to be addressed are the storage retention time of the reservoirs used, the energy penalty of the operation, the extent that CCS technology will be deployed, future emissions scenarios, and the degree of climate sensitivity.  The study finds that CCS technology is worthwhile, and has the potential to significantly curb rising temperatures, especially in the short term.— Shanna Hoversten
  Stone, E., Lowe, J., Shine, K., 2009. The impact of carbon capture and storage on climate. Energy & Environmental Science 2, 81–91.

E.J. Stone and colleagues analyzed the potential benefits of CCS under a variety of circumstances by combining a model of the carbon cycle with a model for CCS storage potential and propensity for leakages.  One of the strengths of this study is that Stone et al. took into account the atmospheric sensitivity to increased CO2, which had previously been ignored in similar models. The study modeled climate change reductions under two IPCC scenarios—the A1F1 which constitutes a fossil fuel intensive world, and the B1 which represents a world driven by clean, resource-efficient technology.  The effects of variable retention times, energy penalties, fractions of fossil fuel emissions released from a single plant, and the fraction of global fossil fuels emissions subject to CCS are then modeled. 
The result is that there are considerable benefits to deploying CCS technology, especially in the short term.  It is much easier to achieve a break-even point for shorter time spans than longer time spans due to the small but constant leakage that will occur from the storage site.  Even so, it may be beneficial to apply this technology in the short term while we are still looking for alternative energy sources that do not emit such a high concentration of CO2.  The importance of these short-term measures will also depend on climate sensitivity, as the maximum temperature reduction benefits of CCS will increase with heightened climate sensitivities. 
Retention time was found to have a significantly greater effect on the efficacy of CCS projects than did other factors such as energy penalty.  Even large energy penalties can be tolerated provided that the retention time of the storage site is adequate.  However that does not mean that storage sites should only be considered if they have the ability to store the CO2 for a 10,000 year duration; one of the most interesting findings of this study was that the use of storage reservoirs previously considered to have insufficiently low leakage rates may still have the potential to confer climate benefits.  Storing the CO2 for even a short period of time may allow for stabilization of atmospheric CO2 concentrations which would in turn reduce climate sensitivity and mitigate substantial rises in temperatures. 

How much CO2 can leak from an underground storage site before it poses a health and safety concern?

Although there is a substantial amount of research into the propensity of storage sites to leak CO2 over time, there is currently an insufficient number of studies addressing the health, safety and environmental (HSE) impacts of these unmitigated leaks (Stenhouse et al. 2009).  The study done by Stenhouse et al. attempts to quantify the impacts of CO2 leakage on human health and safety by examining a scenario in which CO2 leaks directly into an enclosed dwelling, causing increased indoor CO2 concentration, and a scenario whereby CO2 leaks into a source of potable water, thereby causing lead mobilization.  The model predicts that to meet Health Canada’s recommendation for indoor air CO2 concentrations, CO2 leakages into an enclosed house should not exceed 5.4 kg d–1.  Further modelling indicates that aquifers containing unpolluted groundwater can tolerate a leakage rate of 1.7e-4 kg CO2 d–1 without mobilizing enough lead to exceed regulatory limits on lead concentrations in drinking water. A comparison of the two scenarios reveals that the health risks associated with leakage into drinking water occur with a lower level of CO2 leakage than do health risks associated with elevated CO2 levels in the home; thus regulators need to set limits on CO2 leakage using the numbers derived from the water scenario.– Shanna Hoversten.
Stenhouse, M., Arthur, R., Zhou, W., 2009. Assessing environmental impacts from geological CO2 storage. Energy Procedia 1, 1895–1902.

M. Stenhouse and colleagues at Monitor Scientific LLC generate their models determining maximum allowable CO2 leakage based on data from the Weyburn Midale CO2 Storage Project.  To assess acceptable leakage rates into a dwelling, the model is based off of a small one-story house with a ventilation rate of 3.1 exchanges per day, and conservatively assumes that the entire quantity of leaked CO2 enters the dwelling as opposed to some of it getting stuck in the soil due to mass transport resistance.  To identify the effects of CO2 leakage on groundwater, a model was used to simulate the acidification that would gradually occur with the addition of CO2 and the resultant mobilization of lead.  Several simulations were performed to assess the varying impacts of the CO2 given the presence of a combination of minerals in the sediments, including calcite, goethite, and cerrusite. 
The results derived for levels of CO2 leakage rates into houses allowable before health and safety becomes a concern were conservative, but relatively straightforward. The model for the water scenario was able to generate a number for how much additional CO2 could be leaked into the water supply, however, this figure was largely dependent on the variety and concentrations of minerals assumed to be in the aquifer sediments. The model demonstrates that with the addition of 0.01 mol calcite to the water, the change in concentration of lead over time is dramatically effected. Thus safe levels of CO2 leakage into potable water will be rather disparate across a range of sediment geology. Stenhouse et al. conclude that their analysis should be used to provide regulatory bounding limits on CO2 leakage rates, but that there should be a strong site-specific component to guard against over reliance on the model.  Further, the paper goes on to suggest a number of areas that require additional research in order to gain a fuller understanding of the health, safety and environmental impacts of CO2 leakage from storage sites.  Some of these topics include: the propensity of high CO2 concentrations to cause tree kills, the effect of intermediate CO2 concentrations over long periods of exposure, and the effect of heightened CO2 concentrations on underground microbial populations and the subsequent ecological consequences. 

The United States may not have as much economically viable underground CO2 storage space as previously thought

A new model to predict the economic viability of CO2 geosequestration in sandstone saline aquifers indicates that previous estimates for storage potential in the U. S. may be overly optimistic (Eccles et al., 2009).  The model identifies an estimated minima for storage costs in a typical basin in the range of $2–7 per ton CO2 sequestered, based on estimates of a maximum CO2 storage potential and a maximum CO2 injection rate.    Eccles et al. use data from carbon capture and storage pilot projects to explain that many assumptions in their model lead to artificially high estimates for the maximum storage potential and the maximum injection rate, and as a result, they conclude that geosequestration will be even more expensive than their model conservatively indicates. However, Eccles et al. proceed to apply the model to identifying economically optimal storage basins in the United States.— Shanna Hoversten
 
Eccles, J., Pratson, L., Newell, R., Jackson, R., 2009. Physical and Economic Potential of Geological CO2 Storage in Saline Aquifers. Environmental Science & Technology 43, 1962–1969.

 

J. K. Eccles and colleagues at the Nicholas School of the Environment, Duke University, begin building their model by estimating maximum storage potential as a function of the optimal injection depth and the available void space in the formation.  However, this estimate does not account for the reality of most pilot projects, during which the CO2 has bypassed the majority of the available pore space.  The maximum injection rate is calculated based on a determination of the injection-induced pressure that would cause hydraulic fracturing beyond the perforated zone around the well. However, comparison of the modelled results with the pilot project at Nagaoka, Japan indicates that lower injection rates are probably more realistic due to engineering constraints and actual reservoir conditions.  The cost per ton of CO2 sequestered is generated based on the total cost of drilling, injection, equipment, and operation and maintenance, notably excluding the costs that would arise from capture and transport of the CO2.  Finally, the cost for storage in a typical basin in the United States was computed using estimates for storage potential and the cost per ton of CO2 stored. 

Results from the modelling indicate that although depth is an important determinant of storage potential, it is not the most important factor in storage cost.  While increased depth can increase the cost by a factor of two, layer thickness and permeability of the storage reservoir can increase cost by a factor of fifty.  This hints at the myriad of basin characteristics that need to be assessed before arriving at a viable cost estimate.  Additionally, costs within a single basin are likely to differ considerably due to the extreme variability in aquifer characteristics.  The most important conclusion that can be drawn from this analysis is that the amount of CO2 storage provided by low-cost regions within saline aquifers in the United States is considerably lower than the estimates reported by previous studies.  The study by Eccles et al. suggests that there are only perhaps ten storage reservoirs in the United States that would have an average storage cost of below $10 per ton CO2.  If more basins are to become economically viable for CO2 storage, then policymakers will need to devise a regime that imposes a rather significant cost on carbon.—Shanna Hoversten