Chapter 20 Carbon Capture and Storage for Mitigating Climate Changes

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Table 20.3. Methods for mobile/distributed point or non-point source CO₂ capture^a

Methods	Description
Alternatives for non-point source CO₂ capture:
Trees/organisms	Capture CO₂ via photosynthesis (e.g., reforestation or avoiding deforestation); cost range 0.03-8$/t-CO_2;one-time reduction, i.e., once the forest mature, no capture; release CO₂ when decomposed Develop dedicated biofuel and biosequestration crops (e.g., switchgrass); enhance photosynthetic efficiency by modifying Rubisco genes in plants to increase enzyme activities; choose crops that produce large numbers of phytoliths (microscopic spherical shells of silicon) to store carbon for thousand years.
2) Ocean flora	Adding key nutrients to a limited area of ocean to culture plankton/algae for capturing CO₂. Utilize biological/microbial carbon pump (e.g., jelly pump) for CO₂ storage. Problems/concerns: a) large-scale tests done but with limited success; b) limited by the area of suitable ocean surface; c) may have problems to alter the ocean’s chemistry; and d) mechanisms not fully known.
3) Biomass-fueled power plant, bio-oil and biochar	Growing biomass to capture CO₂ and later captured from the flue gas. Cost range = 41$/t-CO₂ By pyrolyzing biomass, about 50% of its carbon becomes charcoal, which can persist in the soil for centuries. Placing biochar in soils also improves water quality, increases soil fertility, raises agricultural productivity and reduce pressure on old growth forests pyrolysis can be cost-effective for a combination of sequestration and energy production when the cost of a CO₂ ton reaches $37 (in 2010, it is $16.82/ton on the European. Climate Exchange).
4) Sustainable practices, e.g., Soils/grasslands peat bogs	Farming practices (e.g., no-till, residue mulching, cover cropping, crop rotation) and conversion to pastureland with good grazing management would enhance carbon sequestration in soil. Peat bogs inter ~25% of the carbon stored in land plants and soils. However, flooded forests, peat bogs, and biochar amended soils can be CO₂ sources.
Alternatives for mobile/distributed point source CO₂ capture:
5) Solid sorbents Organics/polymers Inorganics/minerals Org. and inorganic hybrids Liquid-impregnated clay	Steel slag & waste concrete: a) Rich in Ca & Mg oxides, readily react w/ CO₂ to form solid carbonates; Cost range = 2–8$/t-CO₂. The annual US production can capture < 1% of US emissions; b) examples of cementitious materials are cement (CSA Type 10, Type 30), fly ash, ground granulated blast furnace slag, electric arc furnace slag, and hydrated lime. Ceramics (containing alkaline or alkaline earth elements): a) trap CO₂ via a chemical reaction (absorption) with the respective carbonate being produced (e.g.., CaO); b) absorb CO₂ in a wide temp. range (300–400°C up to 800°C). Layered double hydroxides (LDHs): a) in general, they are [M^II_1-xM^III_x(OH)₂]^x+(A^n-)_x/n·mH₂O, where M^II and M^III stand for divalent and trivalent cations occupying octahedral sites within the hydroxyl layers, x = M^III/(M^II+M^III) and takes values in the range of 0.20 to 0.50, and A^n- is an exchangeable interlayer anion. One example is Mg-Al-CO₃ known as hydrotalcitelike, has been widely studied; b) Another form is [Ca₂Al(OH)₆]₂CO₃·mH₂O, a hydrocalumite-like compound having sevenfold-coordinated Ca. Limestone, dolomite, CaO/Ca₁₂Al₁₄O₃₃, etc. Liquid-impregnated clay is capable of capturing CO₂ at lower temperature (30–60^oC), and can be regenerated at 80–100^oC.
6) liquid sorbents (synthetic trees) NaOH/Ca(OH)₂ NH₃ Ion exchange resin/fibers	NaOH has lower vapor pressure to prevent water loss as compared with Ca(OH)₂ scheme; 7–20 $/t-CO₂ for NaOH scheme; 20 $/t-CO₂ for Ca(OH)₂ scheme; the energy requirement of a packed tower contactor similar to the ones used to capture CO₂ from power plant flue gas would be 6–12 times the energy produced when the fossil fuel was initially burned; the water lost by evaporation is a concern. With NH₃ as sorbent, the “energy tower” can be used to capture CO₂ and generate green power. The process has many advantages, i.e., it will promote the use of NH₃ as fuel and NH₃fertilizer industry. Using ion exchange resins/fibers as sorbents may simplify the sorbent regeneration cycle.

^aMajor references: Osborne and Beerling (2006); Stolarooff (2006); Beerling (2008); Choi et al. (2009); Greenleaf and SenGupta (2009); Lackner and Brennan (2009); Liu et al. (2009); Plasynski et al. (2009); Pfeiffer et al. (2011); and de Richter (2012).
Method 4) is very important, and sometimes, these conservation practices are called regenerative agriculture. Currently, worldwide overgrazing is substantially reducing grassland’s performance as carbon sinks. It was suggested that, if practiced on the planet’s 3.5 billion tillable acres, regenerative agriculture [e.g., method 4) in Table 20.3] could sequester up to 40% of current CO₂ emissions. The U.S. CO₂emissions from fossil fuel combustion were ~6170 million metric tons in 2006 (EWR 2009). If a 2,000 (lb/ac)/year sequestration rate was achieved on all 434,000,000 acres (1,760,000 km²) of cropland in the US, about one quarter of the country's total fossil fuel emissions would be sequestered per year (Wikipedia 2012).

Both Methods 5) and 6) depend on the use of reusable sorbents that can be regenerated via a swing of temperature, pressure or chemical reactions. Preliminary systems analysis indicates that CO₂ removal utilizing the solid sorbent [Method 5)] can be more economical than the liquid-amine process [Method 6)] as the regeneration of the solid sorbent requires less energy; the estimated regeneration energy for the solid sorbent is 1,821 KJ/kg CO₂ as compared to 4,648 KJ/kg CO₂ with the liquid-amine process (Siriwardane and Robinson 2009). An ideal sorbent would be inexpensive, abundant, and non-toxic, and have a binding energy with CO₂ > 20 kJ/mol that is required to pull it from the atmosphere (Stolaroff 2006). Lackner and Brennan (2009) stated that a binding energy with CO₂ > 15 kJ/mol is required for flue gas scrubbing processes, and the energy required for recovering CO₂ from a sorbent for air capture or flue gas scrubbing is similar; therefore, the cost of efficient implementations are likely to be similar.

The carbonation of calcium-carrying materials forms thermodynamically stable calcium carbonates (Young et al. 1974):

3CaO · SiO₂ + 3CO₂ + xH₂O→SiO₂ ·xH₂O + 3CaCO₃ (Eq. 20.4)

2CaO · SiO₂ + 2CO₂ + xH₂O → SiO₂ ·xH₂O + 2CaCO₃ (Eq. 20.5)

Ca(OH)₂ + CO₂+ H₂O → CaCO₃ + 2H₂O (Eq. 20.6)

The theoretical maximum CO₂ uptake is a function of the chemical composition of the sorbent (Steinour 1959):

CO₂ (%) = 0.785(CaO − 0.7SO₃) + 1.091MgO + 1.420Na₂O + 0.935K₂O (Eq. 20.7)

The maximum CO₂ uptake for a portland cement of typical composition of 63% CaO is ~50% (Monkman and Shao 2006). Thus, if a 100% degree of carbonation is assumed, the sequestration potential of cement would be 0.5 t CO₂/t cement. The annual US production of steel slag and waste concrete can capture < 1% of US GHG emissions (Stolaroff 2006).

Currently, research on using solid reusable sorbents [e.g., Table 20.2 and Method 5) of Table 20.3] to capture and recover CO₂ from different sources is a focal point. Although many solid sorbents are available, it is a challenge to use them for CO₂ capture from distributed/mobile sources because these sources usually do not generate a large quantity of CO₂. One of the major changes is to regenerate sorbents in a cost effective way. For example, CaO or K₂CO₃ can capture CO₂ via the reactions below:

CaO(s) + CO₂(g) ⇔ CaCO₃(s) (Eq. 20.8)

K₂CaO₃(s) + CO₂(g) + H₂O ⇔ 2KHCO₃(s) + Heat (Eq. 20.9)

However, the standard circulating fluidized bed (CFB) systems are difficult to use for CO₂ capture from distributed/mobile sources because several reactors still are needed to transfer solids (often in a much smaller volume) for sorbent generation. In addition, Ca-or K-based sorbents often show a rapid falloff in reversibility for the reactions shown in Eqs. 8 and 9 due to sintering effects associated with the calcination process (Lu et al. 2009). Pfeiffer et al. (2011) reported that [Ca₂Al(OH)₆]₂CO₃·mH₂O (called CaAl-550) has better properties (efficiency and thermal stability) as a CO₂ sorbent than CaO due to the aluminum presence as Ca₁₂Al¹⁴O₃₃. However, all these solid sorbents need to be operated at a relatively high temperature range. Liquid-impregnated clay, among others is capable of capturing CO₂ at a lower temperature (30–60^oC), and can be regenerated at 80–100^oC (Siriwardane and Robinson 2009), which is more useful for capturing CO₂ from mobile and distributed sources.
In the early 1940s, capturing CO₂ from ambient air with absorbents has been explored (Tepe and Dodge 1943; Spector and Dodge 1946). Large scale scrubbing of CO₂ from ambient air for climate mitigation was first suggested by Lackner in the late 1990’s (Lackner et al. 1999). In wet scrubbing techniques, a contact reactor, as a point of contention, allows CO₂ to be sorbed into the sorbent solution (e.g., NaOH, Ca(OH)₂, NH3, ion exchange resin, etc.) to create an aqueous solution (e.g., NaOH + Na₂CO₃). In the regeneration cycle, a concentrated, pressurized stream of CO₂ is created, along with the regeneration of the sorbent for its reuse. This two-step process is used in almost all of the industrial air capture devices (known as “synthetic trees”) currently. For both flue stack scrubbing and air capture, the most expensive processes are the regeneration cycle, which makes the cost of capturing CO₂ from ambient air slightly higher than those incurred during the conventional capture in flue stacks (Lackner and Brennan 2009).
Currently, research and development (R&D) is mainly focused on two directions, i.e., improvement of the contactor and the regeneration cycle. Large convective tower, packed scrubbing towers, and “energy towers” have been proposed/tested as a contactor or theoretically analyzed (Lackner et al. 1999; Baciocchi et al. 2006; Zaslavsky 2006; Zeman 2007; Mahmoudkhani et al. 2009; de Richter 2012). Zeman (2007) estimated a total energy requirement of 380 kJ/mol of CO₂ for the capture and chemical recovery (using a modified lime cycle as the recovery process). Mahmoudkhani et al. (2009) reduced fluid pumping work by 90% in the packed tower by intermittent operation of the contactor with a 5% duty cycle. In the regeneration cycle, the carbonate solution goes through a crystallizer and becomes solid carbonate, which then goes through a kiln reactor to become CaO, NaO, or KO with pure CO₂ being released (CE 2012). Mahmoudkhani et al. (2009) reported a novel process for removing carbonate ions from alkaline solutions based on titanate compounds and compared it to the traditional lime cycle for the caustic recovery. The titanate process reduces the high-grade heat requirement by ~50%. The results support process design of the titanate cycle. The carbonate solution can also be regenerated via a membrane process (a process under research) and the hydroxyl solution can be reused. The membrane process is an electrodialysis process, and the electricity used is substantial (CE 2012).

Lackner (2009) proposed using an anionic exchange resin (Marathon A), that absorbs carbon dioxide when dry and releases it when exposed to moisture, as a solid sorbent to capture CO₂ directly from ambient air. The ion exchange resin is composed of a polystyrene backbone with quaternary amine ligands attached to the polymer. These quaternary amine groups carry a permanent positive charge. The positive ions fixed to the polymer backbone never release a proton (as NH₄⁺ would). Thus, the resin is more akin to a solidified sodium salt brine than to an ammonia solution, and it readily absorbs CO₂ diluted in the air at a rate of 10–500 μ mol/m²-s (similar to NaOH solution). Then, a water vapor of 45 ^oC is sufficient to drive most of the CO₂ off the resin and have it revert to absorb CO₂. Global Research Technologies, LLC has demonstrated the efficacy of the air extraction device. It is estimated that a cost of $200/ton of CO₂ is needed for a prototype device with early (1990s) design and a cost of $30/ton of CO₂ (≈ $0.25/gallon of gasoline) could be achieved in the near-future (Lackner and Brennan 2009).

Carbon Engineering (Alberta, Canada) developed an “Air Capture” system to capturing CO₂ directly from air (Mahmoudkhani et al. 2009). The system draws air and then sends it to a contactor (similar to a trickling tower) for wet scrubbing–the CO₂ in air is absorbed by the hydroxyl solution and becomes carbonate solution. The system requires an energy source, and produces a stream of pure CO₂as its principal output. The system enables cost-effective industrial scale applications for CO₂ capture from mobile/ distributed emissions sources. A similar concept is to build an “energy tower” for CO₂ capture; a cooling tower with a diameter of 300 m and a height of 800 m would capture 6,8000,000 tC/year and generate 1130 GWh electricity (at 3–5 cts/kWh). Both NaOH and NH₃ can be used as absorbents, but ammonia is more suitable for CO₂ capture because ammonia (a strong base) can be produced from neutral air and water (N₂ + 3H₂O →2NH₃) with renewable energy. Ammonia can be stored and transported in MgCl₂, e.g., in the form of Mg(NH₃)₆Cl₂ and then released at 300°C (ammonia fuel cell) to be used as carbon free energy (Elmøe et al. 2006; de Richter 2012). Ammonia can also be used as a fuel with N₂ and H₂O being the only combustion products (4NH₃ + 3O₂ → 2N₂ + 6H₂O), a zero-emission combustion. In addition, ammonia is a major technology for emission control of NO_x (Fulks et al. 2009). In energy towers fed with NH₃, the CO₂ is captured via the reaction 2NH₃+ CO₂ →→ (NH₃)₂CO₃, and (NH₃)₂CO₃can be used to make urea (H₂N-CO-NH₂). Urea is a fertilizer and is currently produced on a scale of 100,000,000 tons/year worldwide. Therefore, using NH₃ would have many more advantages as compared to NaOH. According to de Richter (2012), only 1600 energy towers worldwide are needed to soak up the 22 billion tons of CO₂ produced annually with green electricity being produced and carbon free fuel (NH₃ or H₂economy) being produced, together with many other advantages. Details are needed about life-cycle assessment of the feasibility of the system.
20.3.2 Transport of CO₂
After capture, CO₂ will be transported via pipeline to suitable storage sites or locations where CO₂ will be used. Usually, CO₂ in the pipeline is at a very high pressure (e.g., ~150 bars), which makes it a supercritical fluid (i.e., the vapor (gas) phase becomes as dense as the liquid phase but flows easily like gases). In addition, CO₂ can be transported with a conveyor belt system or ship for other applications.
Currently, most of the pipelines are built for transport CO₂ to oil production fields for EOR purposes. For example, at Weyburn, the CO₂ is a purchased by-product from the Dakota Gasification Company’s synthetic fuels plant in Beulah, North Dakota; the CO₂ (95%) is transported through a 320-km pipeline at a rate of about 5,000 tonnes/day. Only a few of the pipelines are used in several pilot projects to test the long-term storage of CO₂ in different geologic formations. In the future, a massive pipeline network will be needed if large-scale CCS implementation occurs, which will raise several issues, such as a) regulatory classification of CO₂ itself (commodity or pollutant), b) economic regulation, c) utility cost recovery, d) pipeline right-of-ways, e) pipeline safety, f) environmental impact. Optimization of pipeline network in concert with sophisticated CCS (e.g., zero-emission power generation plants), CO₂ inventory (what, where, when), renewable energy technologies, and CO₂ reuse technologies is needed and will be very challenging.
20.3.3 Long-Term Storage of CO₂
As shown in Table 20.4 (Cuff and Goudie 2008), the major long-term storage (sequestration) technologies included: a) geological, b) mineral, and c) ocean storage.
Geological Storage. Currently, geological storage may be the most popular option. The total worldwide CO₂ storage capacity is ≥ 2000 – 10,000 Gt (IPCC 2005; Plasynski et al. 2009; Lin 2010), which is enough to store emissions at the current emission rate of about 28 Gt per year. Table 20.5 shows examples of commercial geological storage deployment. There are a dozen of small- or pilot-scale demonstration projects in the world. At Weyburn site, ~18 million tons CO₂have been injected between 2000 and 2010 (July); ultimately 20 million tons of CO₂ are expected to be stored. The EOR is expected to enable an additional 130 million barrels of oil to be produced and extend the life of Weyburn field by 25 years. Current cost is about $20/ton of CO₂ (MIT 2012). Many industrial applications have injected large volumes of CO₂ underground. EOR operations in many parts of the US have been initiated with individual injection values as large as 3 MMt/year (810,000 t C) and cumulative injections of anthropogenic CO₂ of about 10 MM t CO₂/y (2.7 MM t C) (Cuff and Goudie 2008). It should be pointed out that, in many EOR projects, there is almost no monitoring beyond that required for CO₂-flood operations (Cuff and Goudie 2008), which is a concern of the technology because pressure connection can induce fluid flows over very long distances. Shukla et al. (2011) used a two-dimensional (2D) axisymmetric numerical model to predict the displacement of an ideal CO₂ reservoir with 30 years of injection and 70 years of monitoring phase; they found an induced vertical displacement of less than 3 mm at the caprock-reservoir interface at the end of the 100-year period. Therefore, the injection of supercritical CO₂ does not cause any significant disturbance to the stress field and stability of the geological formations in the reservoir if the reservoir has a nearly intact caprock (free of any major faults or fractures).
Table 20.4. CO₂ storage Technologies^a

Geological storage options and worldwide CO₂ storage capacity (C in Gt CO₂):

Saline formations contain brine in their pore volumes, commonly with salinities > 10,000 ppm. C > 1000.
Declining oil and gas fields have some combination of water and hydrocarbons in their pores. Examples include enhanced oil or gas recovery. C = 675‒900.
Unminable coalbeds (= CO₂ enhanced coalbed methane, CO₂-ECBM). C = 3‒200.

Concerns and needs:

Little is known about saline aquifers compared to oil fields; as the salinity of the water increases, less CO₂ can be dissolved into the solution. Larger uncertainty about the saline aquifers exists if the site appraisal study is limited.
Liquid CO₂ is nearly incompressible with a density of ~1000 kg/m³; overpressuring and acidification of the reservoir may cause a) changes in the pore/mineral volume, d) saline brines (or water) moving into freshwater aquifers or uplift; old oil wells may provide leak opportunities.
In CO₂-ECBM, the key reservoir screening criteria include laterally continuous and permeable coal seams, concentrated seam geometry, minimal faulting and reservoir compartmentalization, of which there is not much known.
New technologies are needed to ensure CO2 stays in place forever.
Need thorough site appraisal studies to reduce harmful effects.

Mineral storage options:

Natural silicate minerals can be used in artificial processes that mimic the natural weathering process; alkaline industrial wastes can also be considered. It is a permanent storage option, and has minimal monitoring requirements.
Magnesium and calcium silicate deposits are sufficient to fix the CO₂ that could be produced from the combustion of all fossil fuels resources. To fix a tonne of CO₂ requires about 1.6 to 3.7 tonnes of rock.

Concerns and needs:

The kinetics of natural mineral carbonation is slow. To speed up the process, solid reactants and additives are needed.
The resulting carbonated solids must be stored at environmental suitable locations.
Needs: a) to reduce cost and energy requirement; b) to integrate/optimize power generation, mining, carbonation reaction, carbonates’ disposal, transport of materials, and energy in a site-specific manner; and c) demonstration plants/projects.

Ocean storage options (capacity > 40000 Gt in water column but (66‒100) x10⁶ Gt if marine sediments considered):

CO₂ dispersal in a very dilute form at depths of 1000–2000 m, a most promising option in the short-term. The cost of capturing the CO₂ + transporting it 500 km + storing it = ~ $70/tonne CO₂.
Injecting CO₂ directly into the sea at > 3000 m to for a lake of liquid CO₂ on the seabed.
Formation of a sinking plume (e.g., bicarbonate) to carry most of the CO₂ into deeper water.
Release of carbonate minerals to accelerate carbonate neutralization.

Concerns and needs:

Concerns: a) unknown impact on ecosystems (e.g., ocean acidification, wildlife, oxygen supply); b) difficult to certify the dissolution, leakage and location of CO₂; c) unknown impact on microbial carbon pump and biological carbon pump.
Needs: a) making reliable predications of the technical feasibility and storage times; b) understand how to predict and minimize any environmental impact; and c) making reliable cost estimates and assess the net benefit.

^aMajor references: Stevens and Spector (1998); IEA (2004); IPCC (2005); Schiller (2007); Cuff and Goudie (2008); Hoffman (2009); Plasynski et al. (2009); Lin (2010); MIT (2012); and Reeves (2012).
Table 20.5. Three large-scale CO₂ injection projects (Wikipedia 2010, 2011, 2012)

Site/start date	Geo-formation	Reservoir type	Permeability	Seal type
Sleipner, Norway, 1996	Offshore saline	Deep-water sandstone	Very high	Thick shale
Weyburn, Canada, 2000	Onshore EOR	Ramp carbonate	Moderate	Evaporate
In Salah, Algeria, 2004	Krechba Carboniferous Fm.	Fluvial/tidal sandstone	Low	Thick shale

Storage of CO₂ in deep saline formations does not produce value-added by-products, but it has other advantages, such as: a) its carbon storage capacity is large, making them a viable long-term solution. For example, in the US, such capacity is > 12,000 billion tonnes of CO₂; b) most existing large CO₂ point sources are within easy access to a saline formation injection point, and therefore it is compatible with near-zero carbon emissions; c) a significant baseline of information and experience exists. For example, information generated by the oil industry on injecting brines from the recovered oil into saline reservoirs can be used (DOE 2012). In addition, coupled reactive transport models for heat and density driven flow in CO2 storage in saline aquifers have been proposed and evaluated (Li 2011).

Coal has the capacity to hold considerably more CO₂ than either CH₄ or N₂ in the adsorbed state (in an approximate ratio of 4:2:1). Operational practices for CO₂-ECBM recovery are still in its infancy. Field experiments in San Juan Basin, USA indicated that the process is technically and economically feasible. To date, over 2 Bcf of CO₂ has been sequestered. Enhancement of gas production can be as high as 150% over conventional pressure-depletion methods. Dewatering of the reservoir is also improved. ECBM development may be profitable in the San Juan basin at wellhead gas prices above $1.75/Mcf, adding as much as 13 Tcf of additional methane resource potential within this mature basin (Stevens and Spector 1998). The RECOPOL (Reduction of CO₂ emission by means of CO₂storage in coal seams in the Silesian Coal Basin of Poland) project indicates that injection in coal seams is not trivial as coal is swelling, causing the reduction of permeability, which may be the reason why the gas production rate was lower than expected (even though gas production is enhanced). Relative low permeability limits injectivity to be probably < 100 ton/d-vertical well, which requires a large number of wells for injection (Lin 2010).
The world is rich in coal-bed methane (CBM) resources; the gas content of some of the coal basins has been confirmed. These coal basins have significant CO₂-ECBM potential. In the U.S., CO₂-ECBM can be used in many places, such as the Texas Gulf Coast, Northern Appalachia and Illinois/Indiana (Reeves 2012). Coal basins in Australia, Russia, China, India, Indonesia and other countries also have large CO₂-ECBM potential. Results from research held in 29 sites for potential CBM and ECBM in China have determined that CO₂ storage potential is about 143Gt in the countries coal bed. This could sequester CO₂ emissions for an estimated 50 years based on China’s CO₂ emission levels in 2000. Simultaneously, the production of methane from ECBM has been estimated to reach 3.4 and 3.8 Tm³ respectively, which equates to 218 years of production at China’s 2002 production rates (Hongguan et al. 2007). Actually, the total worldwide potential for CO₂-ECBM is estimated at approximately 68 Tcf, with about 7.1 billion metric tons of associated CO₂ sequestration potential. If viewed purely as a non-commercial CO₂ sequestration technology, the worldwide sequestration potential of deep coal seams may be 20‒50 times greater (Stevens and Spector 1998). In addition, ECBM techniques may be applied to tap remaining gas in coal after production in a secondary production phase.
Mineral Storage. In recent years, carbonation of magnesium- and calcium- based silicates has emerged as a potential option for CO₂ storage. The major metal oxides of Earth’s Crust include: SiO₂ (59.71%), Al₂O₃ (15.41%), CaO (4.90%), MgO (4.36%), Na₂O (3.55%), FeO (3.52%), Fe₂O₃ (2.63%). In mineral sequestration process, CO₂exothermically reacts with available metal oxides to form stable carbonates (CaCO₃, MgCO₃, Na₂CO₃, FeCO₃, K₂CO₃, and FeCO₃). Theoretically, up to 22% of the earthen mineral mass is able to form carbonates. The process occurs naturally over many years. For example, silicate mineral weathering is a combination of dissolution of calcium silicate minerals and carbonate precipitation, and the nest reaction is the formation of limestone and silica (SiO₂) (IPCC 2005):

CaSiO₃ + 2H₂O + 2CO₂ Ca²⁺+ 2HCO₃^- + SiO₂ + H₂O (Eq. 20.10)

Ca²⁺+ 2HCO₃^- CaCO₃ + H₂O + CO₂(Eq. 20.11)

CaSiO₃+ CO₂  CaCO₃ + SiO₂ (Eq. 20.12)

Similarly, CO₂ can react with other earthen oxides and be sequestrated as carbonates:

Ca(OH)₂ + 2CO₂  Ca(HCO₃)₂ (Eq. 20.13)

Mg(OH)₂ + 2CO₂ Mg(HCO₃)₂ (Eq. 20.14)

CaCO₂ + CO₂ + H₂O  Ca(HCO₃)₂ (Eq. 20.15)

CaO + 2CO₂ + H₂O  Ca(HCO₃)₂ (Eq. 20.16)

MgO + 2CO₂ + H₂O  Mg(HCO₃)₂ (Eq. 20.17)

Serpentine Mg₃Si₂O₅(OH)₄ and Olivine Mg₂SiO₄ are the most abundant Mg-silicates. It has been proposed to use them for CO₂storage (IPCC 2007):

Mg₃Si₂O₅(OH)₄ + 3CO₂  3MgCO₃ + 2SiO₂ +2H₂O, ΔH = - 89 kJ/mol (Eq. 20.18)

Mg₂SiO₄+ 2CO₂  2MgCO₃ + SiO₂, ΔH = - 64 kJ/mol (Eq. 20.19)

The basic steps include: a) mining (and later mine reclamation); b) mineral pretreatment; c) CO₂transport and pre-processing; d) carbonation reaction; and e) product handling and disposal. However, the direct fixation of carbon dioxide on solid unrefined material particles is too slow to be used. To speed up the process, several schemes have been proposed and tested for the mineral carbonation process (Fig. 20.2). All these schemes are energy intensive and costly. For example, the cost of using natural silicate olivine to store CO₂ is $50–100/tCO₂ stored, which is 30‒50% energy penalty on the power plant. Adding 10‒40% energy penalty in the capture plant, a full CCS system with mineral carbonation may need 60‒180% more energy than a power plant with equivalent output without CCS (IPCC 2005).

Ocean Storage. There are four basic ways to store CO₂ in the ocean (see Table 20.4). Currently, major conclusions about these options are based on modeling. CO₂ injected at a depth of 3000 m is a better option because the efficiency of CO₂ retention will be between 48–82% after 500 years, substantially more efficient than the other options (IEA 2004). This is because at the depth of 3000 m, the CO₂ may be denser than the surrounding pore fluids and thus, be gravitationally trapped there. As a result, deep-ocean, sub-seafloor storage appears to offer a particularly safe location to store CO₂. It should be pointed out that, the four options do not consider the contributions by marine organisms via biological carbon pumps, mainly because these pumps are thought to be a slow solution. However, more and more results indicate that our understanding of these topics is very limited, and future breakthrough is possible once the knowledge gap is filled. Some related information is briefly discussed below.

Figure 20.2 CO₂ mineral carbonation processes (Schiller 2007).

On average, the ocean absorbs 2% more carbon than they emit each year, forming an important sink in the overall carbon cycle. CO₂ is absorbed by the ocean as per the reactions below (IPCC 2005):

CO₂ (g) + H₂O ↔ H₂CO₃ (aq) ↔ HCO₃^– + H⁺ ↔ CO₃^2– + 2H⁺ (Eq. 20.20)

Once in the ocean, CO₂ is transported and/or transformed in two major mechanisms:

Physical pump. Cold water holds more CO₂than warm water. Because cold water is denser than warm water, this cold, CO₂-rich water is pumped down by vertical mixing to lower depths. Total dissolved inorganic carbon (DIC) is the sum of carbon contained in H₂CO₃, HCO₃^–, and CO₃^2–, but majorly in the form of HCO₃^–. The net results of adding CO₂ to sea water is the generation of H⁺ (i.e., lowering pH) and decreases the concentration of CO₃^2-.
Biological carbon pump (BCP) forcing CO₂ going through the food chain. This is a process whereby CO₂ in the upper ocean is fixed by primary producers and transported to the deep ocean as sinking biogenic particles or as dissolved organic matter. The fate of most of this exported material is remineralization to CO₂, which accumulates in deep waters until it is eventually ventilated again at the sea surface. However, a proportion of the fixed carbon is not mineralized but is instead stored for millennia as recalcitrant dissolved organic matter.

The consequence of pathways a) and b) are that ocean surface waters are super-saturated with respect to CaCO₃, allowing the growth of corals and other organisms that produce shells or skeletons of carbonate minerals. In contrast, the deepest ocean waters have lower pH and lower CO₃^2– concentrations, and are thus undersaturated with respect to CaCO₃. The net effect of pathway b) is that a large amount of carbon is suspended in the water column as dissolved organic carbon (DOC). For example, green, photosynthesizing plankton converts as much as 60 gigatons of carbon per year into organic carbon‒roughly the same amount fixed by land plants and almost 10 times the amount emitted by human activity. Even though most of DOC is only stored for a short period of time, marine organisms are capable to convert immense amounts of bioavailable organic carbon into difficult-to-digest forms known as refractory DOC; this organisms driven conversion has been named the “jelly pump” (Hoffman 2009) and the microbial carbon pump (MCP) (Jiao et al. 2010). Once transformed into “inedible” forms, these DOCs may settle in undersaturated regions of the deep oceans and remain out of circulation for thousands of years, effectively sequestering the carbon by removing it from the ocean food chain (Hoffman 2010). As shown in Table 20.6, there is a tremendous amount of CO₂ storage capacity in marine sediments and sedimentary rocks. However, what is the contribution due to the inedible forms of DOCs or carbonate compounds that are formed by biological pumps and the related mechanisms are not fully understood yet, rending more studies about the real contribution of these mechanisms to CO₂ storage.

Table 20.6. Capacity of different CO₂ sink (adapted from Hoffman 2009)

Sink	Amount (Gt)	Sink	Amount (Gt)
Atmosphere	578 (as of 1700) 766 (as of 1999)	Marine sediments & sedimentary rocks	60,000,000‒ 100,000,000
Ocean	38,000‒40,000	Soil organic matter	1,500‒1,600
Terrestrial plants	540‒610	Fossil fuel deposits	4,000

20.3.4 Monitoring and Life Cycle Risk Management of CCS
CCS involves 4 major systems: a) capture and compression; b) transportation; c) injection; and d) geological storage reservoir. Each system can leak CO₂ and thus, should be treated as a source for emissions. In this section, however, we will focus on monitoring, verification and accounting (MVA) of CO₂ storage in geological storage reservoirs due to complexity of the system and the related issues. Comprehensive information can be found in NETL (2009).
Leakage, MVA and Life Cycle Risk Management (LCRM) of CCS. For well-selected, designed and managed geological storage sites, IPCC estimates that risks are comparable to those associated with current hydrocarbon activity. Nevertheless, leakage in geological formations is possible, such as leakage a) through poor quality or aging injection well completions, b) through abandoned wells, c) due to inadequate caprock characterization; and d) due to inconsistent or inadequate monitoring. Table 20.7 shows potential risks associated with large-scale injection of CO₂. For example, in January 2011, Weyburn was reported to leak CO₂ at the surface of a pond on a farm around the injection site (MIT 2012). The CO₂ with concentrations > 5‒10% of the air volume is lethal. Therefore, there are serious safety concerns here. Mineral storage is not regarded as having any risks of leakage. However, carbonic acid formed due to the CO₂ storage or mineral processing can release heavy metals from storage sites or minerals, requiring monitoring of the seepage of heavy metals and groundwater contamination. It is very difficult to account for ocean storage as CO₂ mixes throughout the ocean. The IPCC estimates 85% of the sequestered carbon dioxide would be retained after 500 years for depths 3000 m, indicating that the option may still be questionable. In addition, hydrate formation (due to the reaction between liquid CO₂ and water) in deep ocean CO₂ storage would provide sufficient energy to transport CO₂-laden fluid to locations far away from the storage site (Anderson 2003).
MVA of injected CO₂ over the long term are formidable due to harsh environmental conditions and complicated processes involved, combined with the deep location and size of the storage sites. For example, the flux of CO₂ leaving a reservoir is extremely difficult to determine because they might be much smaller than the biological respiration rate and photosynthetic uptake rate of the ground cover. In general, MVA aims at (NETL 2009):

Site performance assessment. This is to a) image and measure CO₂ in the reservoir (e.g., to make sure the CO₂ is effectively and permanently trapped in the deep rock formations), b) show if the site is currently preforming as expected, c) estimate inventory and predicate long-term site behaviors (e.g., enable site closure), and d) evaluate the interactions of CO2 with formation solids and fluids for improved understanding of storage processes, model calibration, future expansion, design improvement;
Regulatory compliance. This is to a) monitor the outer envelope of the storage complex for emissions accounting, b) collect information for regulatory compliance and carbon credit trading, and c) provide a technical basis to assist in legal dispute resulting from any impact of CCS; and
Health, safety, and environmental (HSE) impact assessment. This is to a) detect potentially hazardous leakage and accumulations at or near surface, b) identify possible problems and impact on HSE, and c) collect information for designing remediation plans.

Briefly, the time course of the LCRM of CCS includes:

Development and quality CCS technology → Propose site → Prepare site → operate site → close site → post closure liability.
The LCRM can be classified as three phases:

Pre-operation phase (about 1–2 years), including technology development, site selection, site characterization, and field design;
Operation phase (about 10–50 years), including site construction, site preparation, injection, and monitoring; and
Post-injection phase (about 100–1000 years), including site retirement program, and long-term monitoring (operation, seismic verification, HSE impact).

Risk assessment will be a key ongoing activity that will drive the future activities of the project. Moreover, contingency plants with mitigation strategies need to be established. At each project decision point, the risk assessment needs to be reviewed, and the decision to proceed to the next phase will depend on the ability of the project partners to manage the assessed risks.

Table 20.7. Potential risks associated with large-scale injection of CO₂^a

Phase	Associated risks	Qualification and mitigation strategy
Pre- operation	Problems with licensing/permitting. Poor conditions of the existing well bores. Lower-than-expected injection rates.	Revise injection rates, well members, and zonal isolation. Test all wells located in the injection site and the vicinity for integrity and establish good conditions. Determine new injection rates or add new wells/pools.
Operation	Vertical CO₂ migration with significant rates. Activation of the pre-existing faults/fractures. Substantial damage to the formation/caprock. Failure of the well bores. Lower-than-expected injection rates. Damage to adjacent fields/producing horizons.	The monitoring program will allow for early warning regarding all associated risks and for the injection program to be reconfigured upon receiving of such warnings. If wellbore failure, recomplete or shut it off. Include additional wells/pools in the injection program.
Post-injection	Leakage through pre-existing faults/or fractures. Leakage through the wellbores.	Decrease formation pressure and treat with cement. Test periodically all wells in the injection site. In case of leakage, wells will be recompleted and/or plugged.

^a Adapted from NETL (2009).
Current Methods for MVA and Future Needs. MVA of CO₂ sequestration in different geological formations for CO₂ storage is very challenging because for each setting, there are so many different layers that need monitoring, often, with different methods. For example, for on-shore storage systems (e.g., a CO₂-EOR system), monitoring and measurement are needed in a) CO₂ plume, b) primary seal, c) saline formation, d) secondary seal, e) groundwater aquifer, f) vadose zone, g) terrestrial ecosystem, and g) atmosphere, while for an off-shore storage system, it would need in a)‒d), e) seabed sediments, f) water column and aquatic ecosystem, and g) atmosphere. Currently, available monitoring methods include (NETL 2009):

Atmospheric monitoring tools: such as CO₂ detectors, eddy covariance, advanced leak detection system, laser systems and LIDAR, tracers and isotopes (Campbell et al. 2009).
Near-surface monitoring tools: such as ecosystem stress monitoring, tracers, groundwater monitoring, thermal hyperspectral imaging, synthetic aperture radar, color infrared transparency films, tiltmeter, flux accumulation chamber, induced polarization, spontaneous (self) potential, soil and vadose zone gas monitoring, shallow 2-D seismic.
Subsurface monitoring: such as multi-component 3-D surface seismic time-lapse survey, vertical seismic profile, magnetotelluric sounding, electromagnetic resistivity, electromagnetic induction tomography, injection well logging (wireline logging), annulus pressure monitoring, pulsed neutron capture, electrical resistance tomography, acoustic logging, 2-D seismic survey, time-lapse gravity, density logging, optical logging. Cement bond long, Gamma ray logging, microseismic survey, crosswell seismic survey, aqueous geochemistry, resistivity log.

The criteria of judging which methods are suitable for different settings are a) simple and cost effective (regarding explaining and implementing the method), b) defensible (sufficiently stringent to ensure that the method is of good QA/QC‒quality assurance and quality control), and c) verifiable (the value obtained by the method can be assigned with confidence and certainty).
Currently, many problems exist, such as detection limits and precision levels of different methods have not been completely established; strategies for different locations have not been fully established. The procedures for detecting, locating and then quantifying leakage have not been developed. Sensitivity analysis of different methods is still in their infancy. Current underground storage accounting is at best qualitative. For example, seismic data can show where CO₂exists qualitatively but not quantitatively. Similarly, it is difficult to use chemical samples to verify storage, since CO₂ can take on many different forms and will mingle with carbon resources that were at the site prior to injection (Lankner and Brennan 2009). Several methods have been proposed to improve accounting of stored carbon, such as using C-14 as a tracer for a) monitoring fluxes from geologic sequestration (Bachelor et al. 2008), b) facilitating measurement via sampling (Landcar and Brennan 2009), c) optical techniques with path lengths of ~1 km, and d) computer simulation and model development. In the future, improvement is needed for a) direct emission measurements from existing CO₂-EOR projects, b) controlled release experiments for demonstrating the ability to detect, locate and quantify emissions in various settings, c) best practices and procedures that can be used to respond to any detected changes, d) approaches to distinguish natural ecosystem fluxes, and other anthropogenic emissions from geological storage reservoir emissions, and e) improve detection of small secondary accumulations of CO₂.
20.3.5 Beneficial Uses of CO₂
Carbon dioxide is rather inert and non-reactive. This inertness is the reason why CO₂ has broad industrial and technical applications. Efforts for CO₂ beneficial uses focus on pathways and novel approaches that can use captured CO₂ for value-added products (e.g., chemicals, cements, or plastics) or beneficial activities so that a portion of the CO₂ capture cost can be offset. Usually, LCA must be considered for processes or concepts to ensure that additional CO₂ is not produced, and extra energy not consumed, due to CO₂ reuse processes.
While the concept is relatively new and less well-known compared to other CCS technologies, many different pathways/reuse technologies have been explored (Figure 20.3). In these processes/technologies, CO₂ is either being used a) as a substrate for boosting production (e.g., algae cultivation) or an additive for enhancing the processes (extraction of alumina from bauxite residue), b) as a feedstock for synthesizing stable product (e.g., for urea yielding boosting, polymer processing, liquid fuel production), c) for integration into pre-existing products (e.g., in concrete curing, carbonate mineralization), or d) as a working fluid for enhancing other activities (e.g., EOR, ECBM, EGS). Details of these technologies are described in PB and GCCSI (2011).

Figure 20.3. Schematic diagram of beneficial uses of CO₂ (Damiani et al. 2012)
The global CO₂ reuse market currently amounts to ~80 million tonnes/year, of which ~50 million tonnes per year are used for EOR at a price of $15–19/tonne. Potentially, the global supply of anthropogenic CO₂ is ~500 million tonnes of low-cost (< $20/tonne) high concentration CO₂; at a much higher cost ($50–100/tonne), around 18,000 million tonnes per year could also be captured for CO₂reuse (PB and GCCSI 2011). Advances of CO₂ reuse technologies depends on future carbon restrictions and prices and their interaction with other CCS technologies.

20.4 Concerns, Constrains and Future Perspectives
Concerns. Major public concerns about CCS include: a) limitations of CCS for power plants, b) cost of CCS, c) mandating CO₂ emission reductions at power plants, d) regulating the long-term storage of CO₂, and e) concerns related to HSE. One limitation of CCS is its energy penalty. Wide-scale application of CCS would reduce CO₂ emissions from flue stacks of coal power plants by 85‒90% with an increase in resource consumption by one third. Completing the cycle of carbon capture and storage may double the US industrial electricity price (i.e., from 6 to 12 ȼ/kWh) or increase the typical retail residential electricity price by ~50% (Charles 2009; IPCC 2005). There is a need to invest over $2.5‒3 trillion for CCS deployment from 2010 to 2050, which is about 6% of the overall investment needed to achieve a 50% reduction in GHG emissions by 2050 (IEA 2009). Because CCS is expensive, regulatory frameworks should help in establishing and promulgating best practices and allowing regulated utilities to make investments in capture technologies (Landcar and Brennan 2009). In addition, government should be more involved in clarifying legislation barriers and in the management of safe and permanent carbon storage.
Constrains. The pros and cons of CCS have been discussed recently (IDEA 2012). The opponents of CCS believe that CCS has several constrains, such as:

CCS efficacy: CCS delays inevitable transition to clean energy; CCS distracts attention and resources form clean energy; CCS is not feasible; CCS will take far too long to implement for climate change.
Risks involved: The potential problems associated with CCS are not fully understood. Leakage of CO₂ from CCS facilities is a risk and a burden of taxpayers and our children.
Economics: The estimated costs for CO₂ transportation ($1–3/t-100 km) and sequestration ($4–8/t-CO₂) are small compared to that for CO₂capture ($35–55/t CO₂ capture) (Li et al. 2009). In general, CCS is less cost-effective than renewable energy; CCS raises costs and energy prices, and requires significant water (e.g., power plants with CCS technology needs 90% more freshwater than those without CCS); without a price on carbon, CCS will not fly.

Obviously, constrains a) and c) are related to the regulatory and legal frameworks for GHG emission limits and carbon price. A concrete carbon price would be vital for stable framework for investment in low-carbon technologies such as CCS. Establishment of new regulations (e.g., GHG emission limits) and related permitting pathway for CCS technologies and projects is important. With GHG emission limits imposed, CCS systems will be competitive with other large-scale mitigation options, such as nuclear power and renewable energy technologies (ITF 2010). Constrain b) is related to CCS technologies. It seems that considerable research is needed in the future for a) clearing the uncertainty with long term predictions about submarine or underground storage security, b) developing technologies that can prevent CO₂ leakage from the storage, and c) minimizing possible HSH impacts.

Future Perspectives. We anticipate that future trends/needs will focus on overcoming the following major barriers related to large-scale deployment of CCS:

Technical: While technology currently exists for safe and effective CCS, it is imperative to improve CCS technologies to lower the cost and to reuse CO₂ in a beneficial way:
1. promote government support to establish framework for CCS deployment;
2. foster the success of CCS projects (including commercial-scale demonstrations);
3. conduct cutting-edge research to establish CCS
  1. technologies and the related fundamentals (e.g., long-term strategies for CO₂ source clusters and CO₂ pipeline networks, mapping CO₂storage potential of deep saline formations, value-added CO₂ reuse pathways).
  2. standards and consistent requirements to ensure the safe and effective operation of CCS, MVA and reporting.
4. support international collaboration to facilitate the global deployment of CCS.
Regulatory: Governments (state and federal) must work together to:
1. establish comprehensive climate change legislation (e.g., GHG emission limits, carbon credit trading/carbon price);
2. provide legal and regulatory clarity, authority and support for safe and effective CCS deployment (e.g., clarify agencies for issuing CCS permits, clarifying the right to use geological formation for CO₂ storage, preventing significant environmental impacts in CCS projects, regulating the safety and operation of CCS projects); and
3. address key legal issues and uncertainties related to CCS implementation (e.g., improve long-term liability and stewardship framework; establish procedures for aggregating and adjudicating the use of and compensation for pore space for CCS projects; development of an international MVA protocol for CO₂ storage and allowance of transboundary CO₂ transfer).
Financial: To put specific frameworks and policies in place to support large-scale CCS deployment, governments need to
1. share burdens and benefits of CCS equally among the taxpayers;
2. spread widely cost allocation mechanisms for CCS projects;
3. establish the commercial market at economically viable prices for CCS technologies; and
4. increase funding for CCS demonstration projects to an average annual level of $3.5‒4 billion from 2010 to 2020 and provide $1.5‒2.5 billion per year from 2010 to 2020.
Social barriers. It is important to
1. expand government education and engagement efforts (e.g., develop well-thought-out and well-funded public outreach programs to educate the public about the risks and benefits of CCS technologies; provide enhanced funding for outreach programs);
2. provide transparent information about planned CCS projects in a timely manner to increase public understanding of CCS benefits and risks (e.g., develop regulations to require public consultation at and participation in planned CCS projects; create toolkits defining common principles and strategies for public engagement and make them available to the public); and
3. Formalize the existing international network of CCS public education and engagement professionals.

20.5 Summary
In this chapter, we define CCS as any technologies/methods that can a) capture, transport, and store carbon (CO₂), b) monitor, verify and account the status/progress of the CCS technologies employed, and c) advance development/uptake of low-carbon technologies and/or promote beneficial reuse of CO₂. CCS can play a central role in the mitigation of GHG emissions (ITF 2010). The estimated costs for CO₂ transportation ($1–3/t-100 km) and sequestration ($4–8/t-CO₂) are small compared to that for CO₂capture ($35–55/t CO₂ capture) (Li et al. 2009). Currently, CCS technologies are available for large-scale applications, but much more improvements, particularly in CO₂ capture are needed. Currently, there's a huge gap between what can technically do and what we are doing. High costs, inadequate economic drivers, remaining uncertainties in the regulatory and legal frameworks for CCS deployment, and uncertainties regarding public acceptance are barriers to large-scale applications of CCS technologies in the world (CCCSRP 2010). It is imperative to overcome the technical, regulatory, financial and social barriers.

20.6 References
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Anderson, S., and Newell, R. (2003). “Prospects for Carbon Capture and Storage Technologies.” Discussion Paper published by Resources for the Future, Washington, DC. Available at <http://rff.org/rff/Documents/RFF-DP-02-68.pdf> (accessed Feb. 2012).

Bachelor, P. P., McIntyre, J. I., Amonette, J. E., Hayes, J. C., Milbrath, B. D., Saripalli, P. (2008). “Potential method for measurement of CO₂ leakage from underground sequestration fields using radioactive tracers.” J. Radioanal. Nucl. Chem., 277(1), 85–89.

Baciocchi, R., Storti, G., and Mazzotti, M. (2006). “Process design and energy requirement for the capture of carbon dioxide from air.” Chemical Engineering and Processing, 45, 1047–1058.

Beerling, D. (2008). The Emerald Planet: How Plants Changed Earth’s History. Oxford Univ. Press. pp.194–195.

Brune, D. E., Lundquist, T. J., and Benemann, J. R. (2009). “Microalgal biomass for greenhouse gas reductions: Potential for replacement of fossil fuels and animal feeds.” J. Environ. Eng., 135(11), 1136–1144.

Campbell, J. E., Fox, J. F., Davis, C. M., Rowe, H. D., and Thompson, N. (2009). “Carbon and nitrogen isotopic measurements from southern Appalachian soils: Assessing soil carbon sequestration under climate and land-use variation.” J. Environ. Eng., 135(6), 439–448.

CCCSRP (California Carbon Capture and Storage Review Panel) (2010). Findings and Recommendations by the California Carbon Capture and Storage Review Panel. CCCSRP, Dec. 2010. Available at <www.climatechange.ca.gov/ carbon_capture_review_panel/.../2011-01-14...> (accessed Feb. 2012).

Charles, D. (2009). “Stimulus gives DOE billions for carbon-capture project.” Science, 323(5918), 1158.

Choi, S., Drese, J. H., Jones, C. W. (2009). “Adsorbent materials for carbon dioxide capture from large anthropogenic point sources.” ChemSuschem, 2, 796–854.

Cuff, D. J., and Goudie, A. (eds.) (2008). The Oxford Companion to Global Change. Oxford Univ. Press, Oxford, N.Y., 2008.

Damiani, D., Litynski, J. T., Mcllvried, H. G., Vikara, D. M., and Srivastava, R. D. (2011). “The US Department of Energy’s R&D program to reduce greenhouse gas emissions through beneficial uses of carbon dioxide.” Greenhouse Gases Sci. Technol., 1, 1–11.

de Richter, R. (2012). “Optimizing geoengineering schemes for CO₂ capture from Air.” PPT slides Available at

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