**4. Carbon dioxide sequestration**

The potential of CO2 sequestration in geologic formations is possible from the fact that certain reservoirs naturally trap and store oil and natural gas over long geological time periods until extracted [1, 4, 6, 16]. In so doing, CO2 from power plants and industrial facilities can be trapped and stored in potential geologic formations. A large percentage of the originally injected CO2 gets trapped in the pores of the geologic formation, while a portion of it is dissolved in the oil and also end up trapped [3, 6, 17]. These trapping processes continue as long as the CO2 is injected. Percentage of stored CO2 is based on total injected volumes and not on the purchased volume and is given as [10].

$$\text{CO}\_{2\text{atmge}}(\%) = \left(\text{CO}\_{2\text{injectd}} - \text{CO}\_{2\text{prodacel}} - \text{CO}\_{2\text{loss}}\right) / \text{CO}\_{2\text{prodabed}}\tag{1}$$

where, *CO*2*storage* is the CO2 storage in metric, *CO*2*injected* is the total CO2 injected, *CO*2*produced* is the CO2 produced, and *CO*2*purchased* is the purchased CO2 injected. CO2 losses is estimated as the difference between total CO2 injected and CO2 produced. Losses may be due to leakages, infrequent power outages, among others [10].

CO2 can be injected into conventional geological formations and stored deep underground. Most of these conventional geologic formations are at depths greater than 800 m, which eventually converts the injected CO2 into its supercritical state. The supercritical CO2 with a higher density than its gaseous state results in a given volume of rock capable of holding more mass of CO2 [4, 7]. For an effective conventional geological storage, approximately 90–95% of the injected CO2 for will be sequestered within the reservoir [4, 9, 16].

#### **4.1. Storage mechanisms in conventional reservoirs**

Trapping mechanisms encountered in CO2 -storage in conventional geologic formations include [9–11]:

• Physical trapping: hydrodynamic, stratigraphic, or structural) trapping

This involves the migration of generated hydrocarbons from organic matter (source) over long geological periods from the source rock to porous and permeable reservoir rock initially saturated with brine. The accumulated hydrocarbons are trapped below a non-permeable cap rock to prevent further migrations, and the density difference between the fluids separates the fluids into layers with gas on top, followed by oil and brine at the bottom. A similar mechanism is encountered in the case of CO2 storage, where the less dense supercritical CO2 plume rises due to buoyancy forces and is prevented from escaping by overlying low permeability cap rock [15]. This mechanism is considered to be relatively fast but requires characterization of the cap rock [2, 3].

• Solubility trapping

**Figure 1.** Schematic diagram of a closed loop CO2

62 Carbon Capture, Utilization and Sequestration

**Figure 2.** CO2



CO2 is widely accepted to be soluble in water, as such, dissolved CO2 can be safely stored in a geologic formation under solubility trapping. Since the CO2 - saturated brine is denser than the unsaturated surrounding brine, density difference causes the denser brine to migrate deeper into the formation and slowly dilutes the unsaturated brine through contact. Reservoir pore pressure, temperature, and salinity of formation water are vital for solubility trapping [16]. This process occurs faster than pure diffusion, prevent CO<sup>2</sup> from hydrodynamically separating from other phases, and it is estimated to begin between a year and hundreds of years after CO2 injection, also dependent on the permeability of the formation in question [2, 20].

if this much is recorded in an unconsolidated formation, how much more there is to expect in

Coal beds are either too deep or too thin to be economically developed, as such, they could

methane gas to be extracted and preferentially adsorb onto the mineral surface for permanent

following parameters (**Table 1**) as reported in a successful project carried out in Canada [10].

EOR, while a total of 370 billion metric tons has been stored/sequestered in the process [4].

storage site selection and injection are regulated by the U.S. Federal and State agencies, in

 to humans and the environment [1, 10, 18]. Specific regulations and particular tools are commonly implemented to selected reservoirs by different companies and agencies [1, 10].

Furthermore, the Safe Drinking Water Act (SDWA) and the U.S. Environmental Protection

Underground Injection Control Program (UICP) considers the previous seismic history as

storage projects.

–storage. Yet they are not thoroughly characterized and are on a small magnitude for

storage potential due to the adsorptive nature of the pore surfaces [4, 13]. In CO2

–

65


is injected into deep coal seams to desorb

http://dx.doi.org/10.5772/intechopen.78235

gas. The criteria for secure storage involve some of the

Carbon Dioxide Utilization and Sequestration in Kerogen Nanopores

storage projects carried out in some major oil basins

capture and storage to reduce the potential risk of stored

sequestration sites to reduce the risk of small earth-

has been utilized worldwide for CO2

injection and monitoring. Whereas, the

. **Table 3** presents a list of moni-

with minimum risks of

a consolidated formation.

–storage [8, 19, 21].

leaking due to the buoyancy of CO2

**4.2. Storage criterion**

**Table 2** summarizes CO2

**4.3. Carbon storage regulation**

addition to checking systems for CO2

a requirement in selecting geologic CO2

toring tools used for CO2

Adequate depth (> 1000 meters)

Minimally faulted, fractured or folded

Adequate volume and permeability for storage

**Table 1.** Criteria for storage on a basin scale [10].

Strong confining seals

No significant diagenesis

enhanced coalbed methane (ECBM) production, CO2

Nonetheless, not all geologic formations will effectively store CO<sup>2</sup>


around the world. A total of 1297 billion barrels of CO<sup>2</sup>

Agency (EPA) impose safety requirements on CO<sup>2</sup>

quakes as well as the effect of earthquakes on leakage of CO<sup>2</sup>


• Coal beds

offer CO<sup>2</sup>

CO2

CO2

CO2

CO2

• Mineral trapping

This process occurs over longer geological timescales than the other trapping methods, but is equally important [3]. It involves the formation of carbonic acids (H2 CO<sup>3</sup> ) as a result of CO2 dissolution in formation brine. The resulting acid is unstable and dissociates to form groups, which react with the formation rock over long periods of time [2, 3]. In situations where, carbonate minerals are precipitated through the reaction, CO2 is permanently trapped as a result [23].

• Capillary (residual) trapping

In a conventional sandstone oil reservoirs, brine is mostly designated as the wetting phase, while oil and gas are the non-wetting phases. In the case of carbonate rocks, oil is the wetting phase and water and gas are the non-wetting phases. In capillary trapping, the formation wetting phase surrounds the CO2 and traps it as immobile pore scale bubbles. This process occurs over shorter time scale (right after injection) [15] compared to the other trapping mechanisms [2, 19]. In effect, the rock surface is presumed to be less water-wet in the presence of CO<sup>2</sup> and in the absence of oil [9].

These trapping mechanisms occur in geologic storage including [13, 14]:

• Depleted oil and gas reservoirs

Not only do these geologic formations provide a means for storing CO<sup>2</sup> , but also offer economic opportunities as the injected CO2 recovers additional oil from depleted oil and gas reservoirs. Moreover, additional revenue can be obtained from the cost of selling captured CO2 to EOR operators to fund the cost of capture technology at industrial facilities and power plants [4, 14, 17]. CO2 is injected underground and remains immobile due to some of the enumerated trapping mechanisms listed above [3, 20].

• Deep saline formations

Saline aquifers are preferred due to their large capacities and being geographically widespread. These include porous rock formations saturated with brine at greater depths with overlying shale cap rocks, which are impermeable and act as a seal to prevent CO2 from leaking [4, 17]. The confined CO<sup>2</sup> also undergoes dissolution in the brine, as well as capillary trapping to render the injected CO2 immobile. A study [2] was carried out to measure the maximum saturation and the form of capillary curve in a CO2 – Berea sandstone system through coreflood experiments, representative of a storage location. A capillary trapping capacity of 7.8% of the rock volume for CO2 – Berea sandstone was recorded [2]. This is to say, if this much is recorded in an unconsolidated formation, how much more there is to expect in a consolidated formation.

• Coal beds

unsaturated surrounding brine, density difference causes the denser brine to migrate deeper into the formation and slowly dilutes the unsaturated brine through contact. Reservoir pore pressure, temperature, and salinity of formation water are vital for solubility trapping [16].

ing from other phases, and it is estimated to begin between a year and hundreds of years after

This process occurs over longer geological timescales than the other trapping methods, but is

dissolution in formation brine. The resulting acid is unstable and dissociates to form groups, which react with the formation rock over long periods of time [2, 3]. In situations where,

In a conventional sandstone oil reservoirs, brine is mostly designated as the wetting phase, while oil and gas are the non-wetting phases. In the case of carbonate rocks, oil is the wetting phase and water and gas are the non-wetting phases. In capillary trapping, the formation wet-

over shorter time scale (right after injection) [15] compared to the other trapping mechanisms [2, 19]. In effect, the rock surface is presumed to be less water-wet in the presence of CO<sup>2</sup>

reservoirs. Moreover, additional revenue can be obtained from the cost of selling captured

Saline aquifers are preferred due to their large capacities and being geographically widespread. These include porous rock formations saturated with brine at greater depths with overlying shale cap rocks, which are impermeable and act as a seal to prevent CO2

through coreflood experiments, representative of a storage location. A capillary trapping

to EOR operators to fund the cost of capture technology at industrial facilities and power

is injected underground and remains immobile due to some of the

also undergoes dissolution in the brine, as well as capil-

immobile. A study [2] was carried out to measure

– Berea sandstone was recorded [2]. This is to say,

injection, also dependent on the permeability of the formation in question [2, 20].

from hydrodynamically separat-

) as a result of CO2

, but also offer eco-

– Berea sandstone system

and

from

is permanently trapped as a

CO<sup>3</sup>

and traps it as immobile pore scale bubbles. This process occurs

recovers additional oil from depleted oil and gas

This process occurs faster than pure diffusion, prevent CO<sup>2</sup>

equally important [3]. It involves the formation of carbonic acids (H2

These trapping mechanisms occur in geologic storage including [13, 14]:

Not only do these geologic formations provide a means for storing CO<sup>2</sup>

carbonate minerals are precipitated through the reaction, CO2

CO2

result [23].

CO2

• Mineral trapping

• Capillary (residual) trapping

64 Carbon Capture, Utilization and Sequestration

ting phase surrounds the CO2

• Depleted oil and gas reservoirs

nomic opportunities as the injected CO2

enumerated trapping mechanisms listed above [3, 20].

the maximum saturation and the form of capillary curve in a CO2

in the absence of oil [9].

plants [4, 14, 17]. CO2

• Deep saline formations

leaking [4, 17]. The confined CO<sup>2</sup>

lary trapping to render the injected CO2

capacity of 7.8% of the rock volume for CO2

Coal beds are either too deep or too thin to be economically developed, as such, they could offer CO<sup>2</sup> storage potential due to the adsorptive nature of the pore surfaces [4, 13]. In CO2 – enhanced coalbed methane (ECBM) production, CO2 is injected into deep coal seams to desorb methane gas to be extracted and preferentially adsorb onto the mineral surface for permanent CO2 –storage. Yet they are not thoroughly characterized and are on a small magnitude for CO2 –storage [8, 19, 21].

#### **4.2. Storage criterion**

Nonetheless, not all geologic formations will effectively store CO<sup>2</sup> with minimum risks of leaking due to the buoyancy of CO2 gas. The criteria for secure storage involve some of the following parameters (**Table 1**) as reported in a successful project carried out in Canada [10].

**Table 2** summarizes CO2 -EOR and CO2 storage projects carried out in some major oil basins around the world. A total of 1297 billion barrels of CO<sup>2</sup> has been utilized worldwide for CO2 - EOR, while a total of 370 billion metric tons has been stored/sequestered in the process [4].

#### **4.3. Carbon storage regulation**

CO2 storage site selection and injection are regulated by the U.S. Federal and State agencies, in addition to checking systems for CO2 capture and storage to reduce the potential risk of stored CO2 to humans and the environment [1, 10, 18]. Specific regulations and particular tools are commonly implemented to selected reservoirs by different companies and agencies [1, 10].

Furthermore, the Safe Drinking Water Act (SDWA) and the U.S. Environmental Protection Agency (EPA) impose safety requirements on CO<sup>2</sup> injection and monitoring. Whereas, the Underground Injection Control Program (UICP) considers the previous seismic history as a requirement in selecting geologic CO2 sequestration sites to reduce the risk of small earthquakes as well as the effect of earthquakes on leakage of CO<sup>2</sup> . **Table 3** presents a list of monitoring tools used for CO2 -EOR and CO2 storage projects.

**Table 1.** Criteria for storage on a basin scale [10].

Adequate depth (> 1000 meters) Strong confining seals Minimally faulted, fractured or folded Adequate volume and permeability for storage No significant diagenesis


**Table 2.** CO2 -EOR and CO2 storage in major oil basins of the world [4].

Cement integrity logs Injection logs Pattern and material balance techniques Tracer injection/logging Step rate testing Fluid levels and reservoir pressure

**Table 3.** Reservoir monitoring tools used in CO2 -EOR [10].

#### **5. CO2 storage in unconventional shale reservoirs**

As previously mentioned, conventional oil and/gas reservoirs form from the migration of petroleum and natural gas from the source (organic matter) into permeable reservoir rocks. On the other hand, unconventional shale gas/oil serve as both the source and reservoir for natural gas and liquid hydrocarbon (oil and gas condensate). These shale formations are being developed widely for oil and gas production especially in the United States (U.S) and other parts of the world. Moreover, shale formations are much more abundant and widely distributed [17] than deep un-mineable coal seams and/ or depleted oil and gas reservoirs but have not been extensively analyzed for CO2 sequestration [19]. This is attributed to the ultratight nature of shales but the recent advances in horizontal drilling and hydraulic fracturing offers a new perspective into these formations [5, 19].

shale formations, which controls the gas adsorption capacity. It undergoes different stages of maturity (decomposition) at higher temperatures to produce petroleum and natural gas within the micropores (<2 nm) and mesopores (2–50 nm) [6]. The kerogen pores create a sieve

) and other gas molecules [18, 30]. Thus, shales can adsorb substantial amounts of

for storage in depleted shale gas and oil reservoirs. The horizontal wells as

 on kerogen as well as fracture surfaces [19, 24]. The level maturity of kerogen is measured by the vitrinite reflectance (% Ro), which indicates the onset of oil (0.6–1.0 Ro%), wet gas (<0.80% Ro) and natural gas (>1.4% Ro) generations, respectively [20, 21]. Gas from shale formations are either thermogenic (generated from cracking of organic matter or the secondary

Because the source rock doubles as the reservoir, shales are characterized as very low permeability formations, which form strong confining seals in their own right but have surface adsorptive characteristics. As such, they require the creation of hydraulic fractures to form conduits for introducing fluids and producing them to the surface through horizontal wells. Hydraulic fracturing cracks the shale rock through injections of water, sand and chemicals at high pressure [16]. Horizontal wells with multi-stage hydraulic fractures can then be used

opposed to vertical wells in conventional geologic formations add to the effectiveness of CO<sup>2</sup>

sequestration unlike meth-

Carbon Dioxide Utilization and Sequestration in Kerogen Nanopores

http://dx.doi.org/10.5772/intechopen.78235

67

molecules, making shales more attractive for CO<sup>2</sup>

cracking of oil) or biogenic (generated from microbes) [22, 26].

**Figure 3.** Backscattered electron (BSE) image of Chattanooga shale, Barber County, KS.

for smaller CO2

to inject CO2

ane (CH4

CO2

Shales consist of a mineral matrix (clay, pyrite, carbonate, quartz) embedded with dispersed dark kerogen (organic matter) areas as shown in **Figure 3**. Kerogen is the insoluble solidphase nanoporous component of organic matter (decomposed plant and animal debris) in

**Figure 3.** Backscattered electron (BSE) image of Chattanooga shale, Barber County, KS.

**5. CO2**

Cement integrity logs

Tracer injection/logging

Pattern and material balance techniques


**Region CO2**

66 Carbon Capture, Utilization and Sequestration

Fluid levels and reservoir pressure

**Table 3.** Reservoir monitoring tools used in CO2

Injection logs

**Table 2.** CO2

Step rate testing

 **storage in unconventional shale reservoirs**

**-EOR (Billion Barrels)**

Asia Pacific 47 13 Central & South America 93 27 Europe 41 12 FSU 232 66 Middle East/North Africa 595 170 North America/Other 38 11 North America/U.S. 177 51 South Africa/Antarctica 74 21 **TOTAL 1297 370**

**CO2**

 **Storage capacity (Billion Metric Tons)**


storage in major oil basins of the world [4].

have not been extensively analyzed for CO2

offers a new perspective into these formations [5, 19].

As previously mentioned, conventional oil and/gas reservoirs form from the migration of petroleum and natural gas from the source (organic matter) into permeable reservoir rocks. On the other hand, unconventional shale gas/oil serve as both the source and reservoir for natural gas and liquid hydrocarbon (oil and gas condensate). These shale formations are being developed widely for oil and gas production especially in the United States (U.S) and other parts of the world. Moreover, shale formations are much more abundant and widely distributed [17] than deep un-mineable coal seams and/ or depleted oil and gas reservoirs but

tight nature of shales but the recent advances in horizontal drilling and hydraulic fracturing

Shales consist of a mineral matrix (clay, pyrite, carbonate, quartz) embedded with dispersed dark kerogen (organic matter) areas as shown in **Figure 3**. Kerogen is the insoluble solidphase nanoporous component of organic matter (decomposed plant and animal debris) in

sequestration [19]. This is attributed to the ultra-

shale formations, which controls the gas adsorption capacity. It undergoes different stages of maturity (decomposition) at higher temperatures to produce petroleum and natural gas within the micropores (<2 nm) and mesopores (2–50 nm) [6]. The kerogen pores create a sieve for smaller CO2 molecules, making shales more attractive for CO<sup>2</sup> sequestration unlike methane (CH4 ) and other gas molecules [18, 30]. Thus, shales can adsorb substantial amounts of CO2 on kerogen as well as fracture surfaces [19, 24]. The level maturity of kerogen is measured by the vitrinite reflectance (% Ro), which indicates the onset of oil (0.6–1.0 Ro%), wet gas (<0.80% Ro) and natural gas (>1.4% Ro) generations, respectively [20, 21]. Gas from shale formations are either thermogenic (generated from cracking of organic matter or the secondary cracking of oil) or biogenic (generated from microbes) [22, 26].

Because the source rock doubles as the reservoir, shales are characterized as very low permeability formations, which form strong confining seals in their own right but have surface adsorptive characteristics. As such, they require the creation of hydraulic fractures to form conduits for introducing fluids and producing them to the surface through horizontal wells. Hydraulic fracturing cracks the shale rock through injections of water, sand and chemicals at high pressure [16]. Horizontal wells with multi-stage hydraulic fractures can then be used to inject CO2 for storage in depleted shale gas and oil reservoirs. The horizontal wells as opposed to vertical wells in conventional geologic formations add to the effectiveness of CO<sup>2</sup>

sequestration in shales since the horizontal wells contact more of the shale formation and as a result, increase the subsurface production area of the well [19]. More so, CO2 sequestration in shales would not require new infrastructure unlike in conventional saline aquifers [19, 20].

gas sorption properties in coal formations so it is likely to manifest in shales as well. These

tion takes place is much needed. A better understanding of the fluid dynamics in kerogen nanopores and predicting effective transport properties (diffusivity, permeability, etc.) is of

In addition to the trapping mechanisms in conventional reservoirs, organic-rich shales have

Kerogen is the insoluble component of organic matter, and measured in the lab as the total organic carbon (TOC) through pyrolysis. Thus, both hydrodynamic trapping and trapping

Tao and Claren [19] developed a linear relationship between TOC and adsorption capacity using a number of published data sets as input into (Eqs. (2) and (3)), respectively for methane

[*CH*4](*cm*<sup>3</sup> /*g*) = 3.04 + 0.35(*TOC*(%)) (2)

[*CO*2](*cm*<sup>3</sup> /*g*) = 0.08 + 1.72(*TOC*(%)) (3)

gen due to its smaller molecular diameter [19]. Accordingly, we produced a TOC vs. gas adsorption capacity plot but with a focus on the level of TOC and its effect on gas adsorption capacity. Shale formations are in abundance and have diverse geologic settings throughout the U.S. (Appalachian basin, Williston basin, Illinois basin, Michigan basin, Permian basin,

tent (TOC) and this variation in TOC has been found to impact the storage capacity of shales. **Figure 4** shows the TOC – gas adsorption capacity for a number of published TOC data [5, 19, 22, 23] ranging from low TOC (<1 wt. %), medium TOC (1 wt. % < TOC < 10 wt. %), high

capacity is seen in the ultrahigh TOC region, followed by significant adsorption capacity in the high TOC region; the least adsorption capacity is observed at low TOC region. This implies

expected through adsorption trapping with subsequent production of significant amounts

displaced in the process. Therefore, conventional structural trapping becomes dominant

TOC (10 wt. % < TOC < 20 wt. %), and ultrahigh TOC (>20 wt. %) [24]. Highest CO2

that, the higher the kerogen content in shales, a significant amount of CO<sup>2</sup>

is able to diffuse more readily than CH<sup>4</sup>

sequestration in shale formations looks promising, however, the

sequestration applications in shales. Also, it would aid

Carbon Dioxide Utilization and Sequestration in Kerogen Nanopores

through adsorption in the presence of kerogen [30].

in in shales.

–EGR/EOR in organic-rich shales. Therefore, the

sequestration in kerogen nanopores

http://dx.doi.org/10.5772/intechopen.78235

69

adsorption capacity to be steeper than

storage [19, 23] but vary in kerogen con-

into the porous kero-

adsorption

sequestration is

sequestration in kerogen nanopores, where most of the sequestra-

phenomena could also be well understood through experimental methods [16, 19].

With these new insights, CO<sup>2</sup>

utmost importance to practical CO2

an added advantage of trapping CO2

) and carbon dioxide (CO2

in capitalizing on the full potential of CO2

focusing on the effect of adsorption was applied.

application of lattice Boltzmann method (LBM) for CO<sup>2</sup>

through adsorption are dependent on the wettability of CO<sup>2</sup>

).

The resulting plot showed the regression line of CO2

and Gulf Coast Region) for EOR and associated CO<sup>2</sup>

, implying that CO2

 **sequestration in shales**

underlying physics of CO2

**5.1. Mechanisms of CO2**

(CH4

that of CH4

CH4

Most of the shale formations are located at greater depths, where the injected CO2 is in its supercritical state, which is much preferred for both CO2 – enhanced gas/oil recovery (EGR)/ EOR in addition to CO2 sequestration. The injected CO2 for EGR/EOR in organic-rich shales adsorb onto the rock surface, while concurrently releasing methane gas (CH4 ) and/ or oil for natural gas and oil productions, respectively [8, 22]. Furthermore, since most of the injected CO2 would be adsorbed to the surface of kerogen rather than exist as free gas, the problem of leakage is minimized [8]. Hence, CO2 sequestration in shales is feasible but requires knowledge of the characteristics of different shale formations as well as gas-water-rock interactions, multiphase flow, and reservoir modeling, monitoring and verification [22, 25].

Tao and Claren [19] introduced a computational method based on historical and projected methane (CH4 ) production to estimate the capacity of CO2 sequestration in Marcellus shale in eastern United States. From the results obtained, the Marcellus shale is expected to store between 10.4 and 18.4 Gt of CO<sup>2</sup> (approximately 50% of total US CO2 emissions) between now and 2030. Another point to note from Tao and Claren [19] was that injected CO2 moves through the shale formation faster than producing CH4 through mass transfer kinetics, which enhances CO2 sequestration process in shales. In addition, other major shale plays like Barnett, Eagle Ford, Woodford, could provide incremental storage capacity.

Nuttal [22] performed experiments to estimate CO2 sequestration capacity in organic-rich Devonian black shales of Eastern Kentucky to be 6.8 Gt [19]. CO2 was found to adsorb onto clay and kerogen surfaces. A direct correlation was observed between CO<sup>2</sup> adsorptive capacity and the total organic carbon (TOC), where CO2 adsorption capacity increases with increasing TOC.

Kang et *al.* [6] examined shale capacity in organic-rich shales and their added advantage of allowing linear CO2 molecules to penetrate smaller pores otherwise inaccessible to other hydrocarbon gases. Moreover, molecular interaction of CO2 and kerogen ensures enhanced adsorption for CO2 sequestration in shales. Injected gas (CO2 ) molecules move through the shale formation through either the organics or inorganics (or both in most cases). In the organics, CO2 dissolves into kerogen and diffuses into the kerogen nanopores, whereas, in the inorganics, CO2 flows through irregularly shaped pores of clays, pyrite fambroids, quartz, and carbonates. Gas permeation and history-matching pressure pulse decay experiments revealed that significant amounts of CO<sup>2</sup> gas reached the organics through the inorganic pores.

Busch et *al.* [5] conducted diffusive transport and gas sorption experiments on shale samples. Effective diffusion coefficients increased (implies irreversible storage of CO<sup>2</sup> ) with a corresponding decrease in the concentration of bulk CO2 volume in the sample. The decrease in bulk CO2 volume is attributed to the dissolution of CO<sup>2</sup> in formation water (brine), adsorbed to clay and kerogen surfaces or undergoes geochemical reactions.

Furthermore, reservoir models can be built and used to predict viable CO2 storage in shale reservoirs to model diffusivity, gas-water-rock interactions, and adsorption/desorption characteristics, among others. Notably, the presence of clay bound water is known to change the gas sorption properties in coal formations so it is likely to manifest in shales as well. These phenomena could also be well understood through experimental methods [16, 19].

With these new insights, CO<sup>2</sup> sequestration in shale formations looks promising, however, the underlying physics of CO2 sequestration in kerogen nanopores, where most of the sequestration takes place is much needed. A better understanding of the fluid dynamics in kerogen nanopores and predicting effective transport properties (diffusivity, permeability, etc.) is of utmost importance to practical CO2 sequestration applications in shales. Also, it would aid in capitalizing on the full potential of CO2 –EGR/EOR in organic-rich shales. Therefore, the application of lattice Boltzmann method (LBM) for CO<sup>2</sup> sequestration in kerogen nanopores focusing on the effect of adsorption was applied.

#### **5.1. Mechanisms of CO2 sequestration in shales**

sequestration in shales since the horizontal wells contact more of the shale formation and as

in shales would not require new infrastructure unlike in conventional saline aquifers [19, 20].

natural gas and oil productions, respectively [8, 22]. Furthermore, since most of the injected

edge of the characteristics of different shale formations as well as gas-water-rock interactions,

Tao and Claren [19] introduced a computational method based on historical and projected

in eastern United States. From the results obtained, the Marcellus shale is expected to store

Kang et *al.* [6] examined shale capacity in organic-rich shales and their added advantage

shale formation through either the organics or inorganics (or both in most cases). In the organ-

carbonates. Gas permeation and history-matching pressure pulse decay experiments revealed

Busch et *al.* [5] conducted diffusive transport and gas sorption experiments on shale samples.

reservoirs to model diffusivity, gas-water-rock interactions, and adsorption/desorption characteristics, among others. Notably, the presence of clay bound water is known to change the

dissolves into kerogen and diffuses into the kerogen nanopores, whereas, in the inor-

flows through irregularly shaped pores of clays, pyrite fambroids, quartz, and

sequestration in shales. Injected gas (CO2

Effective diffusion coefficients increased (implies irreversible storage of CO<sup>2</sup>

Furthermore, reservoir models can be built and used to predict viable CO2

now and 2030. Another point to note from Tao and Claren [19] was that injected CO2

(approximately 50% of total US CO2

sequestration process in shales. In addition, other major shale plays like Barnett,

molecules to penetrate smaller pores otherwise inaccessible to other

gas reached the organics through the inorganic pores.

would be adsorbed to the surface of kerogen rather than exist as free gas, the problem of

sequestration

) and/ or oil for

– enhanced gas/oil recovery (EGR)/

for EGR/EOR in organic-rich shales

sequestration in Marcellus shale

through mass transfer kinetics, which

sequestration capacity in organic-rich

adsorption capacity increases with increasing TOC.

was found to adsorb onto clay

and kerogen ensures enhanced

volume in the sample. The decrease in

in formation water (brine), adsorbed

) molecules move through the

) with a corre-

storage in shale

adsorptive capacity and

emissions) between

moves

sequestration in shales is feasible but requires knowl-

is in its

a result, increase the subsurface production area of the well [19]. More so, CO2

supercritical state, which is much preferred for both CO2

through the shale formation faster than producing CH4

Nuttal [22] performed experiments to estimate CO2

the total organic carbon (TOC), where CO2

EOR in addition to CO2

68 Carbon Capture, Utilization and Sequestration

leakage is minimized [8]. Hence, CO2

between 10.4 and 18.4 Gt of CO<sup>2</sup>

CO2

methane (CH4

enhances CO2

of allowing linear CO2

that significant amounts of CO<sup>2</sup>

adsorption for CO2

ics, CO2

ganics, CO2

bulk CO2

Most of the shale formations are located at greater depths, where the injected CO2

sequestration. The injected CO2

adsorb onto the rock surface, while concurrently releasing methane gas (CH4

multiphase flow, and reservoir modeling, monitoring and verification [22, 25].

) production to estimate the capacity of CO2

Eagle Ford, Woodford, could provide incremental storage capacity.

and kerogen surfaces. A direct correlation was observed between CO<sup>2</sup>

Devonian black shales of Eastern Kentucky to be 6.8 Gt [19]. CO2

hydrocarbon gases. Moreover, molecular interaction of CO2

sponding decrease in the concentration of bulk CO2

volume is attributed to the dissolution of CO<sup>2</sup>

to clay and kerogen surfaces or undergoes geochemical reactions.

In addition to the trapping mechanisms in conventional reservoirs, organic-rich shales have an added advantage of trapping CO2 through adsorption in the presence of kerogen [30]. Kerogen is the insoluble component of organic matter, and measured in the lab as the total organic carbon (TOC) through pyrolysis. Thus, both hydrodynamic trapping and trapping through adsorption are dependent on the wettability of CO<sup>2</sup> in in shales.

Tao and Claren [19] developed a linear relationship between TOC and adsorption capacity using a number of published data sets as input into (Eqs. (2) and (3)), respectively for methane (CH4 ) and carbon dioxide (CO2 ).

$$[\text{CH}\_4] \text{(}cm^3/\text{g)} = 3.04 + 0.35 \text{(TOC(\%))} \tag{2}$$

$$[\text{CO}\_2] \text{(}cm^3/g\text{)} = 0.08 + 1.72 \text{(TOC(\%))}\tag{3}$$

The resulting plot showed the regression line of CO2 adsorption capacity to be steeper than that of CH4 , implying that CO2 is able to diffuse more readily than CH<sup>4</sup> into the porous kerogen due to its smaller molecular diameter [19]. Accordingly, we produced a TOC vs. gas adsorption capacity plot but with a focus on the level of TOC and its effect on gas adsorption capacity. Shale formations are in abundance and have diverse geologic settings throughout the U.S. (Appalachian basin, Williston basin, Illinois basin, Michigan basin, Permian basin, and Gulf Coast Region) for EOR and associated CO<sup>2</sup> storage [19, 23] but vary in kerogen content (TOC) and this variation in TOC has been found to impact the storage capacity of shales.

**Figure 4** shows the TOC – gas adsorption capacity for a number of published TOC data [5, 19, 22, 23] ranging from low TOC (<1 wt. %), medium TOC (1 wt. % < TOC < 10 wt. %), high TOC (10 wt. % < TOC < 20 wt. %), and ultrahigh TOC (>20 wt. %) [24]. Highest CO2 adsorption capacity is seen in the ultrahigh TOC region, followed by significant adsorption capacity in the high TOC region; the least adsorption capacity is observed at low TOC region. This implies that, the higher the kerogen content in shales, a significant amount of CO<sup>2</sup> sequestration is expected through adsorption trapping with subsequent production of significant amounts CH4 displaced in the process. Therefore, conventional structural trapping becomes dominant

fall short of capturing molecular pore wall effects. On the other hand, the lattice Boltzmann method (LBM), a mesoscopic numerical method is more flexible and less time consuming since a unit of gas molecules is assigned a distribution function for simulation [25, 26].

As previously outlined, the injected gas first contacts the fracture/matrix interface and then chooses to either (1) dissolve into the organic material (kerogen) and diffuse through a nanopores network or (2) enter the inorganic material and flow through a network of irregularly

The lattice Boltzmann method (LBM) is a numerical method for simulating fluid at the molecular scale. This method is ideal for simulating gas flow in nanoporous kerogen since the continuum flow (Darcy's law) fails due to dominating pore-wall effects at the microscale. LBM stems from the Boltzmann kinetic theory of gases, where fluids are assumed to be made up of a large number of small particles in random motion, which undergo elastic collisions to conserve mass and momentum [19, 23, 24]. However, the LBM replaces the fluid molecules with fractious particles to reduce the number of possible particles to a handful [28]. The fractious particles are

in **Figure 4**, where the direction index *i* = 0, 1, …, 8, for a D2Q9 model [29] (**Figure 5**). Following the kinetic theory, the fractious particles stream along defined lattice links and collide locally at varying lattice sites [23–25]. The streaming and collision of fluid particles by the Bhatnagar-Gross-Krook (BGK) approximation gives the lattice Boltzmann BGK equation as [19, 23–26].

(*x*, *t*) = −\_\_1

*τ*[*f i* (*x*, *t*) − *f i*

*i*

 **sequestration**

(scCO2

Carbon Dioxide Utilization and Sequestration in Kerogen Nanopores

http://dx.doi.org/10.5772/intechopen.78235

*i*

) with porous kero-

71

in organic-rich shales. We

) at each node as shown

*eq*(*x*, *t*)] (4)

with porous kerogen focusing

shaped voids [6, 18]. Therefore, the interaction of supercritical CO2

gen needs to be investigated for long-term reservoir storage of CO2

then confined to the nodes of the lattice and assigned lattice velocities (*e*

(*x* + *ei t*, *t* + *t*) − *f*

**Figure 5.** D2Q9 (2-D, 9-velocities) lattice nodes and velocities. Modified from [29].

provide a simulation study that reveals the interaction of scCO2

on two key features of adsorption and diffusion.

**5.2. Lattice Boltzmann simulation (LBS) of CO<sup>2</sup>**

*i*

*f*

**Figure 4.** Gas adsorption capacity as a function of different levels of TOC.

in low TOC regions, where shale only serves as a cap rock/seal to prevent dissolved CO2 from leaking to the surface since the mechanism of adsorption into porous kerogen (TOC) surface is close to negligible. On the other hand, within high TOC (>2 wt. %) regions, the adsorption trapping mechanism onto the kerogen surface prevails and render shale as storage medium in itself. In other words, shales with high TOC tend to be strongly CO2 -wet, whereas shales with low TOC content exhibit water-wet conditions, with medium TOC in between strongly CO2 –wet and water-wet conditions [24]. Furthermore, the presence of interlayering clay minerals (illite) in shales also creates a large surface area for adsorption, although the weight of TOC has a much larger influence [25].

The properties of supercritical CO2 inside small pores are of interest for subsurface carbon storage and as such require an understanding of the processes that govern the gas transport process [19, 23]. Molecular dynamics (MD) among other microscopic computational fluid dynamics as well as analytical models based on Fick's law for gas have been applied to understand the diffusion of CO<sup>2</sup> and CH4 into organic pores. While, molecular dynamics simulates kerogen pore structures with the use of molecular sieves to investigate gas transport, analytical models modify continuum approaches by incorporating slip flow and diffusion. However, molecular dynamics is not feasible to simulate gas flow in porous media at large scale due to computational time and memory constraints [25, 26] and analytical models fall short of capturing molecular pore wall effects. On the other hand, the lattice Boltzmann method (LBM), a mesoscopic numerical method is more flexible and less time consuming since a unit of gas molecules is assigned a distribution function for simulation [25, 26].

As previously outlined, the injected gas first contacts the fracture/matrix interface and then chooses to either (1) dissolve into the organic material (kerogen) and diffuse through a nanopores network or (2) enter the inorganic material and flow through a network of irregularly shaped voids [6, 18]. Therefore, the interaction of supercritical CO2 (scCO2 ) with porous kerogen needs to be investigated for long-term reservoir storage of CO2 in organic-rich shales. We provide a simulation study that reveals the interaction of scCO2 with porous kerogen focusing on two key features of adsorption and diffusion.

#### **5.2. Lattice Boltzmann simulation (LBS) of CO<sup>2</sup> sequestration**

in low TOC regions, where shale only serves as a cap rock/seal to prevent dissolved CO2

itself. In other words, shales with high TOC tend to be strongly CO2

**Figure 4.** Gas adsorption capacity as a function of different levels of TOC.

has a much larger influence [25].

70 Carbon Capture, Utilization and Sequestration

The properties of supercritical CO2

to understand the diffusion of CO<sup>2</sup>

leaking to the surface since the mechanism of adsorption into porous kerogen (TOC) surface is close to negligible. On the other hand, within high TOC (>2 wt. %) regions, the adsorption trapping mechanism onto the kerogen surface prevails and render shale as storage medium in

low TOC content exhibit water-wet conditions, with medium TOC in between strongly CO2 –wet and water-wet conditions [24]. Furthermore, the presence of interlayering clay minerals (illite) in shales also creates a large surface area for adsorption, although the weight of TOC

storage and as such require an understanding of the processes that govern the gas transport process [19, 23]. Molecular dynamics (MD) among other microscopic computational fluid dynamics as well as analytical models based on Fick's law for gas have been applied

simulates kerogen pore structures with the use of molecular sieves to investigate gas transport, analytical models modify continuum approaches by incorporating slip flow and diffusion. However, molecular dynamics is not feasible to simulate gas flow in porous media at large scale due to computational time and memory constraints [25, 26] and analytical models

and CH4

from


inside small pores are of interest for subsurface carbon

into organic pores. While, molecular dynamics

The lattice Boltzmann method (LBM) is a numerical method for simulating fluid at the molecular scale. This method is ideal for simulating gas flow in nanoporous kerogen since the continuum flow (Darcy's law) fails due to dominating pore-wall effects at the microscale. LBM stems from the Boltzmann kinetic theory of gases, where fluids are assumed to be made up of a large number of small particles in random motion, which undergo elastic collisions to conserve mass and momentum [19, 23, 24]. However, the LBM replaces the fluid molecules with fractious particles to reduce the number of possible particles to a handful [28]. The fractious particles are then confined to the nodes of the lattice and assigned lattice velocities (*e i* ) at each node as shown in **Figure 4**, where the direction index *i* = 0, 1, …, 8, for a D2Q9 model [29] (**Figure 5**). Following the kinetic theory, the fractious particles stream along defined lattice links and collide locally at varying lattice sites [23–25]. The streaming and collision of fluid particles by the Bhatnagar-Gross-Krook (BGK) approximation gives the lattice Boltzmann BGK equation as [19, 23–26].

$$f\_i(\mathbf{x} + e\_i \,\Delta t, \mathbf{t} + \Delta t) - f\_i(\mathbf{x}, t) = -\frac{1}{\tau} [f\_i(\mathbf{x}, t) - f\_i^a(\mathbf{x}, t)] \tag{4}$$

**Figure 5.** D2Q9 (2-D, 9-velocities) lattice nodes and velocities. Modified from [29].

where, *f i* (*x*, *t*) is the density distribution function, *f i eq*(*x*, *t*) is the equilibrium distribution function, *τ* is the relaxation time. The left-hand side (LHS) of (Eq. (2)) represents the streaming step, while the right-hand side (RHS) constitutes the collision step.

In effect, collision of fluid particles is considered as a relaxation towards a local equilibrium, and defined for every model with varying dimensions (2-D, 3-D) and velocities (5, 9, 15, etc.).

The LBM models the distribution of and changes in the density function, from which the velocity profile is determined. Accordingly, the macroscopic fluid density and velocity are given respectively as [19, 23, 24].

$$\rho = \sum\_{i=0}^{8} f\_i \tag{5}$$

$$
\mu = \frac{1}{\rho} \sum\_{i=0}^{8} f\_i e\_i \tag{6}
$$

Marcellus shale reservoir conditions were implemented at a high pressure of 12 MPa and temperature of 300 K. The D2Q9 LBM diffusion coefficient is known to be given in (Eq.(8)) and

(center) and CO2

<sup>3</sup>(*τσ* <sup>−</sup> \_\_1

and CO2

wetting phase, while methane occupies the center as the non-wetting phase.

vailing temperature and pressure. Furthermore, the diffusion coefficient CO<sup>2</sup>

ary condition is implemented at the upper and lower walls, while the pressure boundary condition is applied to the east and west ends. **Figure 6** shows the static velocity profile of

and CH4

 sequestration in organic-rich shales to mitigate greenhouse gas (GHG) effects is proven to be very feasible through experimental and numerical simulations. Our literature review

<sup>2</sup>) (8)

(at the walls) in a 20 nm pore-slit.

Carbon Dioxide Utilization and Sequestration in Kerogen Nanopores

http://dx.doi.org/10.5772/intechopen.78235

73

at 12 MPa. Hydrodynamic velocity bound-

, respectively, it was found that CO2

at *τ* = 1 is higher

diffusion

for the same pore dimension and pre-

occupies the surface of the pore walls on both ends as the

at *<sup>τ</sup>* <sup>=</sup> 0.8. The estimated magnitude of CH4

/s in carbon molecule sieves [19].

is the relaxation time for each

is directly comparable to the kinematic viscosity [28, 32].

where, *D* is the diffusion coefficient of the D2Q9 LBM and *τσ*

*D* = \_\_1

**Figure 6.** Composite velocity distribution of both CH4

A 20-nm pore-slit is filled with both CH<sup>4</sup>

Estimating the amount of adsorbed gas for CO2

coefficient is given in the range of 10−13–10−10 m2

adsorption capacity was much more than that of CH4

both fluids in the pore-slit; CO<sup>2</sup>

than the diffusion coefficient of CH<sup>4</sup>

fluid component.

**6. Conclusions**

CO2

where, *ρ* is the macroscopic fluid density and *u* is the macroscopic fluid velocity.

Several works [18, 29] have been carried out on modeling the convection problem encountered in deep saline aquifers during CO2 sequestration with the lattice Boltzmann method (LBM). The findings include the fact that brine with a high CO<sup>2</sup> concentration was found to invade into the underlying unsaturated brine, causing an increase in the interfacial area between the CO2 –rich brine and CO2 – deficient brine. In effect, this phenomenon enhanced the migration of CO2 into the fracture and pores.

However, in organic-rich shales, most of the sequestration process takes place within the kerogen nanopores through adsorption [30, 31]. In so doing, there is the need to understand the interaction of supercritical CO2 (scCO2 ) with porous kerogen for long-term reservoir storage of CO2 in organic-rich shales.

In a typical kerogen nanopore, the velocity is discontinuous at the pore wall due to the mean free path of the gas molecules exceeding the characteristic length (pore size). This phenomenon is characterized by the Knudsen number (*<sup>K</sup> <sup>n</sup>* ); slip flow regime falls within 0.001 <sup>&</sup>lt; *<sup>K</sup> <sup>n</sup>* <sup>&</sup>lt; 0.1. For chosen characteristic length 20 nm for our LBS (*<sup>K</sup> <sup>n</sup>* <sup>=</sup> 0.0243), fluid flow falls within the slip flow regime. Slip flow boundary condition was modified for CO<sup>2</sup> molecules, which are predicted to not reflect at the walls but rather adsorb and desorb after some time lag [26, 27]. In effect, the velocity of the pore wall is defined to be dependent on the surface diffusion coefficient of CO<sup>2</sup> gas as well as Langmuir adsorption parameters based on the amount of adsorbed gas. Hence, the slip velocity at the pore-wall is given by [26, 27, 30].

$$
\mu\_{s\vert p} = \left(1 - \alpha\right)\mu\_{\frac{s}{2}} + \alpha\mu\_{\frac{s}{2}} \tag{7}
$$

where, *uslip* is the slip velocity, *ug* is the fluid velocity away from the wall, *uw* is the local wall velocity dependent on the surface diffusion coefficient, and *α*is the amount of adsorbed gas at the solid surface through Langmuir isotherm.

Carbon Dioxide Utilization and Sequestration in Kerogen Nanopores http://dx.doi.org/10.5772/intechopen.78235 73

**Figure 6.** Composite velocity distribution of both CH4 (center) and CO2 (at the walls) in a 20 nm pore-slit.

Marcellus shale reservoir conditions were implemented at a high pressure of 12 MPa and temperature of 300 K. The D2Q9 LBM diffusion coefficient is known to be given in (Eq.(8)) and is directly comparable to the kinematic viscosity [28, 32].

$$D = \frac{1}{3} \left( \tau\_o - \frac{1}{2} \right) \tag{8}$$

where, *D* is the diffusion coefficient of the D2Q9 LBM and *τσ* is the relaxation time for each fluid component.

A 20-nm pore-slit is filled with both CH<sup>4</sup> and CO2 at 12 MPa. Hydrodynamic velocity boundary condition is implemented at the upper and lower walls, while the pressure boundary condition is applied to the east and west ends. **Figure 6** shows the static velocity profile of both fluids in the pore-slit; CO<sup>2</sup> occupies the surface of the pore walls on both ends as the wetting phase, while methane occupies the center as the non-wetting phase.

Estimating the amount of adsorbed gas for CO2 and CH4 , respectively, it was found that CO2 adsorption capacity was much more than that of CH4 for the same pore dimension and prevailing temperature and pressure. Furthermore, the diffusion coefficient CO<sup>2</sup> at *τ* = 1 is higher than the diffusion coefficient of CH<sup>4</sup> at *<sup>τ</sup>* <sup>=</sup> 0.8. The estimated magnitude of CH4 diffusion coefficient is given in the range of 10−13–10−10 m2 /s in carbon molecule sieves [19].

#### **6. Conclusions**

where, *f i*

(*x*, *t*) is the density distribution function, *f*

given respectively as [19, 23, 24].

72 Carbon Capture, Utilization and Sequestration

*ρ* = ∑

*u* = \_\_1

tered in deep saline aquifers during CO2

the interaction of supercritical CO2

in organic-rich shales.

on the surface diffusion coefficient of CO<sup>2</sup>

the solid surface through Langmuir isotherm.

where, *uslip* is the slip velocity, *ug*

between the CO2

age of CO2

[26, 27, 30].

the migration of CO2

while the right-hand side (RHS) constitutes the collision step.

*i*

*τ* is the relaxation time. The left-hand side (LHS) of (Eq. (2)) represents the streaming step,

In effect, collision of fluid particles is considered as a relaxation towards a local equilibrium, and defined for every model with varying dimensions (2-D, 3-D) and velocities (5, 9, 15, etc.). The LBM models the distribution of and changes in the density function, from which the velocity profile is determined. Accordingly, the macroscopic fluid density and velocity are

> *i*=0 8 *f*

*ρ* ∑ *i*=0 8 *f*

Several works [18, 29] have been carried out on modeling the convection problem encoun-

to invade into the underlying unsaturated brine, causing an increase in the interfacial area

However, in organic-rich shales, most of the sequestration process takes place within the kerogen nanopores through adsorption [30, 31]. In so doing, there is the need to understand

In a typical kerogen nanopore, the velocity is discontinuous at the pore wall due to the mean free path of the gas molecules exceeding the characteristic length (pore size). This

0.001 <sup>&</sup>lt; *<sup>K</sup> <sup>n</sup>* <sup>&</sup>lt; 0.1. For chosen characteristic length 20 nm for our LBS (*<sup>K</sup> <sup>n</sup>* <sup>=</sup> 0.0243), fluid flow falls within the slip flow regime. Slip flow boundary condition was modified for CO<sup>2</sup>

ecules, which are predicted to not reflect at the walls but rather adsorb and desorb after some time lag [26, 27]. In effect, the velocity of the pore wall is defined to be dependent

based on the amount of adsorbed gas. Hence, the slip velocity at the pore-wall is given by

*uslip* = (1 − *α*) *ug* + *αuw* (7)

velocity dependent on the surface diffusion coefficient, and *α*is the amount of adsorbed gas at

is the fluid velocity away from the wall, *uw*

where, *ρ* is the macroscopic fluid density and *u* is the macroscopic fluid velocity.

(LBM). The findings include the fact that brine with a high CO<sup>2</sup>

into the fracture and pores.

(scCO2

–rich brine and CO2

phenomenon is characterized by the Knudsen number (*<sup>K</sup> <sup>n</sup>*

*eq*(*x*, *t*) is the equilibrium distribution function,

*<sup>i</sup>* (5)

*<sup>i</sup> ei* (6)

concentration was found

); slip flow regime falls within

mol-

is the local wall

sequestration with the lattice Boltzmann method

– deficient brine. In effect, this phenomenon enhanced

) with porous kerogen for long-term reservoir stor-

gas as well as Langmuir adsorption parameters

CO2 sequestration in organic-rich shales to mitigate greenhouse gas (GHG) effects is proven to be very feasible through experimental and numerical simulations. Our literature review and LBS suggest that organic-rich shales are capable of storing CO2 in substantial quantities in its adsorbed state in the presence of higher TOC levels. In addition to shales being widely distributed and in abundance, the natural confining seals of the formation reduces the risk of leakage. On the other hand, CO2 -EGR/EOR can be achieved as part of the CO<sup>2</sup> sequestration process; CO2 -EGR/EOR produces relatively clean fuel and sustains energy demands.

Ro % vitrinite reflectance

LBM lattice Boltzmann method

BGK Bhatnagar-Gross-Krook

*τ* relaxation time

*<sup>i</sup>* lattice velocities

GHG greenhouse gas

Kn Knudsen number

MPa mega Pascal

nm nanometer

*uslip* slip velocity

Cudjoe Sherifa\* and Barati Reza

University of Kansas, Lawrence, USA

**Author details**

**References**

K Kelvin

*ρ* macroscopic density *u* macroscopic velocity

*f i*

*f i*

*e*

LBS Lattice Boltzmann simulation

(*x*, *t*) velocity distribution function

*eq*(*x*, *t*) equilibrium distribution function

*D* diffusion coefficient of D2Q9 LBM

\*Address all correspondence to: reza.barati@ku.edu

Economic Competitiveness, and Energy Security; 2016

United Kingdom: Imperial College London; 2010

[1] U.S. Department of Energy. Carbon Capture, Utilization, and Storage: Climate Change,

Carbon Dioxide Utilization and Sequestration in Kerogen Nanopores

http://dx.doi.org/10.5772/intechopen.78235

75

[2] Pentland CH. Measurements of Non-wetting Phase Trapping in Porous Media. London,

D2Q9 2-dimensional, 9 velocity/speed model

However, to accurately benefit from CO<sup>2</sup> – sequestration in organic-rich shales, there is the need to overcome developmental challenges and understand the rock-fluid and fluid–fluid interactions in organic-rich shales for large scale pilot test and implementation.
