**4. Gas-to-liquid using CO2**

#### **4.1. What is GTL?**

Gas-to-liquid (GTL) is the processing of converting natural gas to synthetic oil. This synthetic oil will be the fuel or the product based on hydrocarbon. Liquefied Natural Gas (LNG: for city gas and bunkering fuel), Pipeline Natural Gas (PNG: for city gas), and Compressed Natural Gas (CNG: for vehicles) are classified by their respective transportation technology, but GTL in liquid state at room temperature is the long-chain hydrocarbon products identified by transformation technology of chemical conversion. **Figure 8** shows the transformation technology of GTL production.

Coal, natural gas, and biomass are used as raw materials in Fischer-Tropsch (FT) process while the meaning of GTL is based on conversion of natural gas to pure synthetic oil in removing impurities such as sulfur, aromatic compounds, and metal substances. By refining this synthetic oil, it can produce diesel, naphtha, wax, and other liquid compounds based oil or other special products. This transformation technology is based on FT process, which was developed *ca.* 100 years ago. Technology of pre-treatment of gas, reforming, and upgrading process is in the mature stage, but FT process has been in the stage of commercialization. New technology is continuously developed, and the already developed technology is applied to conversion process for enhancing efficiency. Also mini GTL technology to be applied to small-scaled gas fields is being developed. The factors influencing on competitiveness are enumerated as investment cost, operation cost, materials price, plant dimension, and technology enhancing usability of products.

**Figure 8.** Transformation technology of GTL.



202 Recent Advances in Carbon Capture and Storage







**4. Gas-to-liquid using CO2**

**Figure 7.** Block diagram of urea plant.

Gas-to-liquid (GTL) is the processing of converting natural gas to synthetic oil. This synthetic oil will be the fuel or the product based on hydrocarbon. Liquefied Natural Gas (LNG: for city gas and bunkering fuel), Pipeline Natural Gas (PNG: for city gas), and Compressed Natural Gas (CNG: for vehicles) are classified by their respective transportation technology, but GTL in liquid state at room temperature is the long-chain hydrocarbon products identified by transformation technology of chemical conversion. **Figure 8** shows the transformation tech-

Coal, natural gas, and biomass are used as raw materials in Fischer-Tropsch (FT) process while the meaning of GTL is based on conversion of natural gas to pure synthetic oil in removing

**4.1. What is GTL?**

nology of GTL production.

In comparing with history of coal-to-liquid (CTL) process, GTL is relatively a new technology and globally commercialized facilities are actually very rare. **Table 2** shows the global GTL project status (see **Figure 9**).

Even when a plant in Nigeria is completed, total production capacity of GTL is only 260,000 barrels per day. On the contrary, daily consumed oil in the world is 87 million barrels. Thus, GTL production is not subject to restriction of consumption


**Table 2.** Worldwide GTL project status.

**Figure 9.** GTL and CTL status and project plans.

#### **4.2. Production processing and facility features**

GTL Process is composed of next four main steps.

#### *4.2.1. Step 1: gas pre-treatment (gas clean-up)*

The gas pre-treatment in GTL process is generally to dehydrate and remove sulfur compounds, mercury, and hydrocarbon C3+. It is similar to the requirements of LNG process, but it needs no stage of removal of CO2 .

#### *4.2.2. Step 2: synthesis gas generation*

The production of synthetic gas covers the conversion into CO and H2 mixture by autothermal reforming (ATR) and steam carbon dioxide reforming (SCR). The oxygen needed in ATR is supplied by air or pure oxygen. When using the air, there are some advantages by eliminating the cost of air separation unit (ASU) and electricity cost but finally become obstacles to process due to large volume of nitrogen. By using reformed steam methane, we supply necessary oxygen. However, this method has disadvantage of producing synthetic gas of H2 to CO ratio by 4:1 against the required H2 to CO ratio by 2:1.

SCR reformer has a homogeneous section and a fixed-bed catalyst section and reacts the prereformed natural gas (primarily methane), steam, and carbon dioxide to produce synthesis gas containing the correct amount and ratio of carbon monoxide and hydrogen. The SCR reformer uses exothermic combustion reactions to off-set the endothermic reforming reactions. The resulting exit temperature is around 870°C, and the pressure is 2.5 MPa. The composition of the product syngas (in particular the H2 :CO ratio) is a function of the three key molar feed ratios previously described (steam, oxygen and CO2 ). The ratio of hydrogen to carbon monoxide in the SCR outlet is currently targeted to be 2.0 to provide the correct H2 :CO ratio in the mixed feed into the FT synthesis reactor. The advantage of SCR process is to enable the development of low-quality natural gas fields containing CO<sup>2</sup> or reuses efficiently CO2 emitted from various processes (CO<sup>2</sup> removal and FT process, etc.). **Figure 10** shows the simplistic integrated GT schematic process.

**Figure 10.** Simplistic integrated GTL schematic.

#### *4.2.3. Step 3: FT synthesis and refining*

FT synthesis is to convert synthetic gas into long-chain hydrocarbons. This conversion is made by catalyst. As for catalyst, cobalt is generally applied. For extracting substances for shipping as final products, fractional distillation is required.

#### **4.3. Mini GTL**

**4.2. Production processing and facility features**

GTL Process is composed of next four main steps.

position of the product syngas (in particular the H2

emitted from various processes (CO<sup>2</sup>

simplistic integrated GT schematic process.

molar feed ratios previously described (steam, oxygen and CO2

enable the development of low-quality natural gas fields containing CO<sup>2</sup>

The gas pre-treatment in GTL process is generally to dehydrate and remove sulfur compounds, mercury, and hydrocarbon C3+. It is similar to the requirements of LNG process, but

reforming (ATR) and steam carbon dioxide reforming (SCR). The oxygen needed in ATR is supplied by air or pure oxygen. When using the air, there are some advantages by eliminating the cost of air separation unit (ASU) and electricity cost but finally become obstacles to process due to large volume of nitrogen. By using reformed steam methane, we supply necessary

SCR reformer has a homogeneous section and a fixed-bed catalyst section and reacts the prereformed natural gas (primarily methane), steam, and carbon dioxide to produce synthesis gas containing the correct amount and ratio of carbon monoxide and hydrogen. The SCR reformer uses exothermic combustion reactions to off-set the endothermic reforming reactions. The resulting exit temperature is around 870°C, and the pressure is 2.5 MPa. The com-

carbon monoxide in the SCR outlet is currently targeted to be 2.0 to provide the correct H2

ratio in the mixed feed into the FT synthesis reactor. The advantage of SCR process is to

oxygen. However, this method has disadvantage of producing synthetic gas of H2

to CO ratio by 2:1.

mixture by autothermal

:CO ratio) is a function of the three key

removal and FT process, etc.). **Figure 10** shows the

). The ratio of hydrogen to

or reuses efficiently

to CO ratio

:CO

.

The production of synthetic gas covers the conversion into CO and H2

*4.2.1. Step 1: gas pre-treatment (gas clean-up)*

**Figure 9.** GTL and CTL status and project plans.

204 Recent Advances in Carbon Capture and Storage

it needs no stage of removal of CO2

*4.2.2. Step 2: synthesis gas generation*

by 4:1 against the required H2

CO2

For successful mini GTL technology, it is required to develop compact and high-efficient GTL process and modularization techniques for being competitive even as small scaled. It will be efficient technology to be applied to small and medium gas field, associated gas of oilfield, and landfill gas on land and at sea. **Figure 11** shows the example of roadmap toward modular GTL plant.

GTL technology for developing small and medium gas field and associated gas requires following conditions: (1) minimization of plant construction cost for economic feasibility as small-scaled hundreds to thousands barrels/day, (2) compact and mobility for installation in places without infra such as frozen zone of Siberia, (3) easy installation in limited space for application to offshore, and (4) compactification and modularization of compressor and related equipments for simple process and high efficiency.

Further study is to be progressed for small and medium gas fields that are expected to have potential application by mini GTL technology. From long-term point of view, the development of gas-to-liquids-floating production storage and offloading (GTL-FPSO) linked to shipbuilding technology will be applied to small and medium-scaled offshore gas fields as well as the strategy of launching high value-added shipbuilding market is to be established.

**Figure 11.** Example of roadmap toward modular GTL plant (source: S.A. Petrobras).

The micro reactor (synthetic gas + FT synthesis) was developed by CompactGTL Ltd., a manufacturer leading compact GTL technology, and its pilot operation was completed by applying to 20-barrels/day plant with Petrobras in 2011 [4–6]. **Figure 12** shows the example of compact GTL roadmap toward modular GTL plant.

**Figure 12.** Example of compact GTL roadmap toward modular GTL plant (source: Compact GTL Limited).

Also by adopting micro channel technology, Velocys is developing mini GTL plants and reported that a pilot plant of 2.5 gallon per day has been developed. They constructed 6 BPD plant in Brazil under cooperation with Petrobras, MODEC and Toyo Engineering and plan the pilot operation in 2012.

Since micro reaction technology had advantages in its small volume, high heat transmission, and large reactive surface and control of exact reaction time, it will enhance high integration of chemical process, response selectivity, and stability.

#### **5. Summary**

The micro reactor (synthetic gas + FT synthesis) was developed by CompactGTL Ltd., a manufacturer leading compact GTL technology, and its pilot operation was completed by applying to 20-barrels/day plant with Petrobras in 2011 [4–6]. **Figure 12** shows the example of compact

**Figure 12.** Example of compact GTL roadmap toward modular GTL plant (source: Compact GTL Limited).

GTL roadmap toward modular GTL plant.

206 Recent Advances in Carbon Capture and Storage

**Figure 11.** Example of roadmap toward modular GTL plant (source: S.A. Petrobras).

The conversion of CO2 to chemicals and energy products that is currently produced from fossil fuels is also promising due to the high potential market and promising benefits. Methanol is the key feedstock for C1 chemistry, as it is used for producing formaldehyde, acetic acid, chloromethane, and other chemicals for chemical industries. Also, industrial catalysts for methanol synthesis are available for gas containing H2 and CO, which is applied with small quantity of CO2 presented.

The utilization of CO2 to produce chemicals like urea and cyclic carbonates is promising and can be a solution to reduce CO2 emission. However, CO2 still has certain disadvantages as a chemical reactant due to its inert, non-reactive, and low Gibbs free energy properties. DME is versatile and promising solution in the worldwide consideration of clean and low-carbon fuels. It has potential to solve forward problem of certain disadvantages as chemical reactant. Similar application of reaction schemes using CO2 as applied to DME manufacturing is also possible in GTL fields, especially for low-value gas fields involving high CO<sup>2</sup> contents and for landfill gas fields.

## **Acknowledgements**

This study was supported by "Ministry of Trade, Industry and Energy" and "Korea Evaluation Institute of Industrial Technology".

## **Author details**

Wonjun Cho1,\*, Hyejin Yu1 and Yonggi Mo2

\*Address all correspondence to: williamcho86@gmail.com

1 R&D Division, Unisys International (& BF International), Daejeon City, Republic of Korea

2 Department of Chemical Engineering, Hanyang University, Seoul, Republic of Korea

#### **References**


#### **Challenges Associated with CO2 Sequestration and Hydrocarbon Recovery Challenges Associated with CO<sup>2</sup> Sequestration and Hydrocarbon Recovery**

Rouzbeh Ghanbarnezhad Moghanloo, Xu Yan, Gregory Law, Soheil Roshani, Garrett Babb and Wesley Herron Rouzbeh Ghanbarnezhad Moghanloo, Xu Yan, Gregory Law, Soheil Roshani, Garrett Babb and Wesley Herron Additional information is available at the end of the chapter

Additional information is available at the end of the chapter

http://dx.doi.org/10.5772/67226

#### **Abstract**

**References**

208 Recent Advances in Carbon Capture and Storage

[1] Wonjun Cho. Current Status of DME Technology Development in Korea. 2013. Available

[2] Wonjun Cho. KOGAS DME activities for commercialization. Asian DME Conference; 16 November 2011. Available from: http://aboutdme.org/aboutdme/files/cclibraryfiles/

[3] Jumin Youn. The status of DME fuel in Korea. The 6th Korea-China-Japan Petroleum

[4] Fabio Passarelli. Offshore GTL: modular solution for associated gas with variable CO<sup>2</sup>

[5] Ana Paula Fonseca. Compact and other advanced GTL technologies. IGU Committee

from: https://www.youtube.com/watch?v=mktzKbji58A.

filename/000000001976/7asiandme\_kogas\_cho.pdf.

content. 25th World Gas Conference; 7 June 2012.

Meeting (WOC1 and PGC A); 18–21 February 2013.

[6] Available from: http://www.compactgtl.com/about/resources.

Technology Congress; 4–6 September 2013.

In the near- and midterm future, carbon capture and storage (CCS), also called CO2 geosequestration, is likely to play a significant role in the reduction of atmospheric greenhouse gas. By expanding the set of possible sequestration targets, it is expected that CCS will enable larger quantities of CO2 to be sequestered, mitigating human activity-driven climate change. In general, oil and gas reservoirs are ideal geologic storage sites for CO2 because they have successfully held hydrocarbon molecules for millions of years. In addition to the significant and reliable storage capacity of hydrocarbon reservoirs, there is a considerable body of knowledge related to the behavior of hydrocarbon bearing reservoirs, and significant amounts of data are often acquired during their exploitation, factors which improve the economics and safety of any CCS project. By making use of existing and future oil and gas projects, CCS can become a major contributor in the fight against global warming, as well as a sizeable contributor to energy production worldwide. The CCS sequestration targets discussed in this study are sandstones, coal beds, shales, and carbonates. The potential and challenges associated with each of them are discussed in detail, and suggested topics for future research work are provided.

**Keywords:** CO2 EOR, CO2 storage, sandstone, carbonate, shale, coalbed methane

#### **1. Introduction**

Global levels of CO2 in the atmosphere have been steadily rising with the increase of hydrocarbon production and usage. It is estimated that CO2 emissions in the United States were approximately 5.5 billion tons in 2015, the largest volume yet. Anthropogenic greenhouse

© 2016 The Author(s). Licensee InTech. This chapter is distributed under the terms of the Creative Commons Attribution License (http://creativecommons.org/licenses/by/3.0), which permits unrestricted use, distribution, and reproduction in any medium, provided the original work is properly cited. © 2017 The Author(s). Licensee InTech. This chapter is distributed under the terms of the Creative Commons Attribution License (http://creativecommons.org/licenses/by/3.0), which permits unrestricted use, distribution, and reproduction in any medium, provided the original work is properly cited.

gases, such as carbon dioxide (CO2 ), are considered a major contributor to global warming [1]. Sequestration of power plant-generated CO2 through injection into petroleum and gas reservoirs through a process called carbon capture and storage (CCS) or "carbon sequestration" has been proposed as a method for reducing greenhouse gas emissions. Research on the use of CO2 for enhanced oil recovery (EOR) continues with growing interest; however, research concerning terrestrial sequestration of CO2 for environmental purposes, such as CCS, is relatively recent. As a result, fundamental topics of interest in sequestration research are concerned with scientific and technical aspects, as well as practical concerns such as the economic feasibility, safety, and the maximum possible amount of CO2 storage [1]. Therefore, fighting CO<sup>2</sup> emissions with EOR and CCS is a priority, leading to innovations within the petroleum industry.

The process of CCS involves pumping sizeable quantities of atmospheric CO2 underground, where, under the right circumstances, it can remain safely sequestered for thousands or millions of years. The economics of CCS are often unfavorable, especially as CO2 is generally an expense rather than a revenue stream, but by combining the end goal of CCS with enhanced oil recovery (EOR) techniques used in the oil industry, there is the potential that CCS can be made economical while also increasing the productivity and efficiency of existing oil resources.

CO2 EOR generally involves the injection of CO2 into an oil-bearing reservoir in order to decrease oil viscosity, decrease the interfacial tension between oil and water, and increase the elastic energy of the formation, generally resulting in improved oil production. In the case of methane-bearing formations, most notably coal beds, injected CO2 has a far stronger affinity to the formation than methane, resulting in the replacement of adsorbed methane with adsorbed CO2 , both increasing methane production and resulting in the sequestering of large volumes of CO2 .

EOR and CCS projects are both complicated tasks that require a vast understanding of the target reservoir in order to enhance storage capacity and storage time of CO2 , as well as hydrocarbon production. These topics will be discussed in greater detail throughout this paper.

#### **1.1. Trapping mechanisms**

One of the primary considerations when approaching a CCS project is the different mechanisms by which CO2 can become safely sequestered underground. Generally, there are four different trapping mechanisms employed in the sequestration of CO<sup>2</sup> , each of which contributes differently to the duration and volume of CO<sup>2</sup> trapping (**Figure 1**). In the different time stage, those four trapping mechanisms will work together.


pores due to capillary forces. This mechanism immobilizes the CO2 , potentially storing it in the formation for millions of years, just like the fluids it displaced.



**Figure 1.** The four different mechanisms of CO<sup>2</sup> trapping.

Overall, these trapping mechanisms prevent carbon dioxide's upward travel and leakage while increasing the CO2 storage potential and security of the desired formation. Assuming an ideal trapping mechanism, the temperature-related properties of a reservoir must be considered as well. The required temperature to store CO2 underground should be less than the critical temperature of CO2 , making reservoirs such as those in Illinois Basin prime candidates. The critical temperature of CO2 is 87.7°F; naturally, most geological formations exceed this temperature due to geothermal gradient [2].

#### **1.2. Sandstone reservoirs**

gases, such as carbon dioxide (CO2

210 Recent Advances in Carbon Capture and Storage

the use of CO2

fighting CO<sup>2</sup>

CO2

adsorbed CO2

volumes of CO2

.

**1.1. Trapping mechanisms**

nisms by which CO2

CO2

the primary CO2

petroleum industry.

[1]. Sequestration of power plant-generated CO2

research concerning terrestrial sequestration of CO2

EOR generally involves the injection of CO2

methane-bearing formations, most notably coal beds, injected CO2

get reservoir in order to enhance storage capacity and storage time of CO2

different trapping mechanisms employed in the sequestration of CO<sup>2</sup>

• Residual trapping: This phase of trapping starts as soon as the CO2

utes differently to the duration and volume of CO<sup>2</sup>

become trapped and begin accumulating.

stage, those four trapping mechanisms will work together.

economic feasibility, safety, and the maximum possible amount of CO2

The process of CCS involves pumping sizeable quantities of atmospheric CO2

lions of years. The economics of CCS are often unfavorable, especially as CO2

), are considered a major contributor to global warming

reservoirs through a process called carbon capture and storage (CCS) or "carbon sequestration" has been proposed as a method for reducing greenhouse gas emissions. Research on

CCS, is relatively recent. As a result, fundamental topics of interest in sequestration research are concerned with scientific and technical aspects, as well as practical concerns such as the

where, under the right circumstances, it can remain safely sequestered for thousands or mil-

expense rather than a revenue stream, but by combining the end goal of CCS with enhanced oil recovery (EOR) techniques used in the oil industry, there is the potential that CCS can be made economical while also increasing the productivity and efficiency of existing oil resources.

decrease oil viscosity, decrease the interfacial tension between oil and water, and increase the elastic energy of the formation, generally resulting in improved oil production. In the case of

ity to the formation than methane, resulting in the replacement of adsorbed methane with

EOR and CCS projects are both complicated tasks that require a vast understanding of the tar-

One of the primary considerations when approaching a CCS project is the different mecha-

• Structural/stratigraphic trapping: These types of traps are formed from tectonic forces and generally involve physical barriers to flow. An example of this is a thick layer of low permeability rock (caprock), such as shale, where, assuming a favorable structure, rising CO2

is being injected, it is displacing the fluids that are inside the pores of the formation. As

volume migrates upward, small volumes of CO2

carbon production. These topics will be discussed in greater detail throughout this paper.

, both increasing methane production and resulting in the sequestering of large

can become safely sequestered underground. Generally, there are four

for enhanced oil recovery (EOR) continues with growing interest; however,

emissions with EOR and CCS is a priority, leading to innovations within the

through injection into petroleum and gas

for environmental purposes, such as

into an oil-bearing reservoir in order to

storage [1]. Therefore,

has a far stronger affin-

, as well as hydro-

, each of which contrib-

is injected. While the

remain inside these tiny

will

trapping (**Figure 1**). In the different time

underground,

is generally an

Sandstone reservoirs were the primary source of oil production during the early life of the oil industry. Many wells were produced and then abandoned long before the introduction of enhanced oil recovery (EOR) and other modern techniques that have enabled production from formations once thought of as nothing more than barriers to flow or geologic curiosities. In this modern day, sandstone reservoirs, once the workhorse of the oil industry but long since abandoned due to declining production, can be made to once again flow in economic quantities through the use of EOR techniques, such as CO2 injection. While ensuring a renewed flow of oil to an energy-hungry world, CO<sup>2</sup> EOR in these old sandstone reservoirs may also play a major role in the preservation of our environment as injected CO2 can be sequestered in subsurface formations for thousands of years. With these unique opportunities come unique challenges, ranging from the significant reservoir analysis required to ensure a safe sequestration to the infrastructure required to deliver such sizeable quantities of CO2 .

Sandstone reservoirs are particularly notable due to the sheer number of wells drilled in such formations that have been produced throughout the history of the oil industry and have since been abandoned. Due to their number, as well as how much time we have had to accumulate knowledge about their behaviors and the petrophysics involved in their production, sandstone reservoirs are likely to play a major role in any large-scale CCS program.

#### **1.3. Coalbed reservoirs**

Another ideal medium in which to store CO2 is coal beds. Generally used to produce coalbed methane or coal at shallower depths, coal beds have a dual porosity system, which can be classified as primary and secondary porosity system. The pores within the coal matrix make up the primary porosity, while the pore volume of the numerous fractures permeating the coal bed makes up the secondary porosity.

The methane that is the primary target of coalbed drilling is stored in the coal matrix via adsorption. Because CO2 has a greater affinity for coal than methane does, CO<sup>2</sup> is the desired choice to enhance methane recovery, and coal beds are a good place to store CO2 . Coal beds are distinctively different from the conventional hydrocarbon reservoirs in production as well as gas storage mechanisms. In conventional oil reservoirs, CO2 is dissolved in the oil to decrease the viscosity of the oil, resulting in a great deal of CO2 being recovered at the surface along with the produced oil. The "sequestered" CO2 is then only that which dissolves into residual oil or is trapped due to one of the other trapping mechanisms [3]. In the case of coal beds, the majority of CO2 adsorbs directly to the surface of the coal bed, providing a more efficient mechanism of sequestration while also forcing methane off the coalbed surface, helping to release any residual gas production. For example, methane recovery was improved from 77 to 95% of original gas in place at the Allison Unit CO2 -ECBM pilot in the San Juan Basin [4]. Coal beds can act as a significant contributor to CCS through the excellent economics of CO2 -based EOR, as well as the quality of their sequestration.

#### **1.4. Shale reservoirs**

As technology has advanced throughout the years, oil and gas exploration in unconventional shale reservoirs has become the main focus of the oil industry. Horizontal drilling and the hydraulic fracturing of shale formations have allowed us to unlock vast reserves of oil and gas production. Considering shale formations have extremely low permeability (of nanoDarcy in some cases), primary production does not produce the maximum amount of oil possible out of the formation. In most cases, tertiary production or EOR will begin with gas injection, such as carbon dioxide (CO2 ), instead of water flooding because of shale's low permeability and the risk of reactions between the clays and injected water. During this production enhancement, some of the injected carbon dioxide will be permanently stored in the formation with different storage mechanisms, while some will be produced with the oil stream and get recycled back into the formation. CCS in shale reservoirs is often more difficult as less is known about their geology and long-term behaviors.

Shale reservoirs will likely play an important part in future CCS projects due to the scale of many shale reservoirs, their quality as a seal, and the importance of EOR techniques in existing shale plays.

#### **1.5. Carbonate reservoirs**

from formations once thought of as nothing more than barriers to flow or geologic curiosities. In this modern day, sandstone reservoirs, once the workhorse of the oil industry but long since abandoned due to declining production, can be made to once again flow in eco-

sequestered in subsurface formations for thousands of years. With these unique opportunities come unique challenges, ranging from the significant reservoir analysis required to ensure a safe sequestration to the infrastructure required to deliver such sizeable quantities of CO2

Sandstone reservoirs are particularly notable due to the sheer number of wells drilled in such formations that have been produced throughout the history of the oil industry and have since been abandoned. Due to their number, as well as how much time we have had to accumulate knowledge about their behaviors and the petrophysics involved in their production, sand-

methane or coal at shallower depths, coal beds have a dual porosity system, which can be classified as primary and secondary porosity system. The pores within the coal matrix make up the primary porosity, while the pore volume of the numerous fractures permeating the

The methane that is the primary target of coalbed drilling is stored in the coal matrix via

are distinctively different from the conventional hydrocarbon reservoirs in production as

residual oil or is trapped due to one of the other trapping mechanisms [3]. In the case of coal

cient mechanism of sequestration while also forcing methane off the coalbed surface, helping to release any residual gas production. For example, methane recovery was improved from

[4]. Coal beds can act as a significant contributor to CCS through the excellent economics of

As technology has advanced throughout the years, oil and gas exploration in unconventional shale reservoirs has become the main focus of the oil industry. Horizontal drilling and the hydraulic fracturing of shale formations have allowed us to unlock vast reserves of oil and gas production. Considering shale formations have extremely low permeability (of nanoDarcy in some cases), primary production does not produce the maximum amount of oil possible out

choice to enhance methane recovery, and coal beds are a good place to store CO2

well as gas storage mechanisms. In conventional oil reservoirs, CO2

decrease the viscosity of the oil, resulting in a great deal of CO2

along with the produced oil. The "sequestered" CO2

77 to 95% of original gas in place at the Allison Unit CO2


has a greater affinity for coal than methane does, CO<sup>2</sup>

adsorbs directly to the surface of the coal bed, providing a more effi-

may also play a major role in the preservation of our environment as injected CO2

stone reservoirs are likely to play a major role in any large-scale CCS program.

injection. While ensuring a

can be

.

is the desired

is dissolved in the oil to

being recovered at the surface

is then only that which dissolves into


. Coal beds

EOR in these old sandstone reservoirs

is coal beds. Generally used to produce coalbed

nomic quantities through the use of EOR techniques, such as CO2

renewed flow of oil to an energy-hungry world, CO<sup>2</sup>

212 Recent Advances in Carbon Capture and Storage

**1.3. Coalbed reservoirs**

adsorption. Because CO2

beds, the majority of CO2

**1.4. Shale reservoirs**

CO2

Another ideal medium in which to store CO2

coal bed makes up the secondary porosity.

CO2 injection into carbonate reservoirs was first considered in the 1930s but did not become a reality until 1964 in the Mead Strawn field located in Texas. CO<sup>2</sup> injection has since been established as a reliable form of EOR, with results regularly matching or surpassing those of other EOR techniques. In the 1964 example with the Mead Strawn field, oil production was increased by up to 82% beyond the results of a standard water flood [5]. Like many sandstone reservoirs, carbonate reservoirs have a long history and will likely play a significant role in future CO2 EOR and CCS projects.

Hill et al. [6] state carbonate CO2 EOR now produces approximately 305,000 bbls worldwide with an accelerating growth rate. The areas targeted for carbonate CO2 projects in the United States are as follows: Louisiana, Michigan, Mississippi, New Mexico, Oklahoma, Texas, and Wyoming. CO2 production wells provide immense amounts of data on the reservoir response to a CO2 flood compared to saline projects. Azzolina et al. [7] discuss how CO2 EOR is an established method for extending the life of a hydrocarbon sustaining carbonate reservoir.

Dissolved CO2 injection into carbonate subsurface formation increases geologic carbon storage integrity by avoiding dependence on trapping mechanisms. As a result, solubility trapping will dominate until mineral trapping occurs, which is dependent on the formation rock [56]. Izgec et al. observed that solubility storage of CO2 is larger than mineral trapping [1]. Eke et al. [8] state geological CO2 storage in carbonate formations for long timescales (sequestration) relies on the contribution of several CO2 trapping mechanisms: physical trapping in a subsurface formation, solubility trapping, hydrodynamic trapping, and mineral trapping.

## **2. Existing field applications**

With the need for the prompt reduction in CO2 emissions, the development of CCS must be taken seriously, as it has the potential to make a major difference in the levels of atmospheric CO2 . At one time, it was believed that oilfield reservoirs did not have sufficient pore volumes to have a significant impact on CO<sup>2</sup> emissions, but it is now understood that not only are there massive pore volumes available for CCS in depleted major pay zones (MPZs) of reservoirs, but there also exist residual oil zones (ROZs) and transition zones (TZs) in hydrocarbon fields that can be depleted and used for sequestration through quaternary production.

Traditionally, residual oil zones (ROZs) are considered to be uneconomic by the end of their primary or secondary recovery phase due to their extremely low oil saturation. However, Advanced Resources International [9] analyzed the feasibility of using CO2 EOR to recover hydrocarbons from the ROZ and determined that a total of 55 fields in the Permian Basin have the potential to become economic ROZ resources. Simulations using CO2 PROPHET, a water and CO2 flood prediction software available through the US Department of Energy (DOE) website, estimated the recoverable ROZ at 11.9 billion bbls of the 30.7 billion bbls of TZ/ROZ oil in place in these five Permian Basin oil plays [9].

Usage of CO2 injection as a form of EOR has not been limited to pilot and research tests. Kinder Morgan estimated that in the past 37 years, 655 million tons of CO2 have been injected, produced, and recycled back into EOR. This is an average of 17.7 million tons per year, which is enough to negate the yearly emissions of six 500 MW coal-fired electric power plants [10]. Examples of some of these different field applications are given below.

#### **2.1. Permian Basin**

The Permian Basin in West Texas is one of the largest areas employing CCS techniques in ROZ and TZ and is currently undergoing the largest CO2 -enhanced oil recovery (EOR) operation in the world. Most of the ROZs created in this area are due to lateral sweep by hydrodynamics and have thicknesses in excess of 300 feet [11]. While implementation of CO2 floods is not particularly widespread due to the limited availability of CO2 , the Permian Basin has ready access to a pipeline of CO2 originating in natural supplies in Colorado and New Mexico. Of the six CO2 EOR projects in which recovery response has been published for Gulf Coast sandstone reservoirs, recovery factors are from 15 to 23% of original oil in place (OOIP) [12].

#### **2.2. Port Neches**

A CO2 injection project in Port Neches, in a Texas Gulf sandstone, started in September 1993. The field had previously undergone water flooding, leaving a residual oil saturation of 30%. The goal of the project was to recover an additional 10% original oil in place (OOIP) [13]. A follow-up paper recorded that the production peaked at 500 barrels of oil per day (Bopd) (**Figure 2**) and later at 800 Bopd with CO2 injection. The OOIP reduced from 12 to 7 million stock tank barrels (MMSTB) in the main fault block of the reservoir [14].

#### **2.3. Bati Raman field**

In 1986, the Turkish Petroleum Corporation started a large immiscible CO2 injection project; the trend can be seen in **Figure 3**.

#### **2.4. Ordos' Basin**

The evaluation of Changqing oil field, Ordos' Basin, Northwest China, concluded that conducting a CO2 flood after water flooding could produce 119 million tons of oil and sequestrate 273 million tons of CO2 [16]. In 2000, the International Energy Agency Weyburn CO2 Monitoring and Storage Project did a study on CO2 storage in a partially depleted oil reservoir and found that a \$1.5 billion, 30-year commercial CO2 EOR produced an additional 130 million barrels of oil.

**Figure 2.** Production vs. time plot.

but there also exist residual oil zones (ROZs) and transition zones (TZs) in hydrocarbon fields

Traditionally, residual oil zones (ROZs) are considered to be uneconomic by the end of their primary or secondary recovery phase due to their extremely low oil saturation. However,

hydrocarbons from the ROZ and determined that a total of 55 fields in the Permian Basin have

website, estimated the recoverable ROZ at 11.9 billion bbls of the 30.7 billion bbls of TZ/ROZ

produced, and recycled back into EOR. This is an average of 17.7 million tons per year, which is enough to negate the yearly emissions of six 500 MW coal-fired electric power plants [10].

The Permian Basin in West Texas is one of the largest areas employing CCS techniques in ROZ

in the world. Most of the ROZs created in this area are due to lateral sweep by hydrodynam-

sandstone reservoirs, recovery factors are from 15 to 23% of original oil in place (OOIP) [12].

The evaluation of Changqing oil field, Ordos' Basin, Northwest China, concluded that conduct-

flood after water flooding could produce 119 million tons of oil and sequestrate 273

 injection project in Port Neches, in a Texas Gulf sandstone, started in September 1993. The field had previously undergone water flooding, leaving a residual oil saturation of 30%. The goal of the project was to recover an additional 10% original oil in place (OOIP) [13]. A follow-up paper recorded that the production peaked at 500 barrels of oil per day (Bopd)

ics and have thicknesses in excess of 300 feet [11]. While implementation of CO2

stock tank barrels (MMSTB) in the main fault block of the reservoir [14].

In 1986, the Turkish Petroleum Corporation started a large immiscible CO2

flood prediction software available through the US Department of Energy (DOE)

injection as a form of EOR has not been limited to pilot and research tests.

EOR to recover

PROPHET, a water

have been injected,

floods is not

injection project;


originating in natural supplies in Colorado and New Mexico.

injection. The OOIP reduced from 12 to 7 million

EOR projects in which recovery response has been published for Gulf Coast

, the Permian Basin has ready

that can be depleted and used for sequestration through quaternary production.

Advanced Resources International [9] analyzed the feasibility of using CO2

the potential to become economic ROZ resources. Simulations using CO2

Kinder Morgan estimated that in the past 37 years, 655 million tons of CO2

Examples of some of these different field applications are given below.

oil in place in these five Permian Basin oil plays [9].

214 Recent Advances in Carbon Capture and Storage

and TZ and is currently undergoing the largest CO2

particularly widespread due to the limited availability of CO2

and CO2

Usage of CO2

**2.1. Permian Basin**

Of the six CO2

**2.2. Port Neches**

**2.3. Bati Raman field**

**2.4. Ordos' Basin**

ing a CO2

the trend can be seen in **Figure 3**.

A CO2

access to a pipeline of CO2

(**Figure 2**) and later at 800 Bopd with CO2

**Figure 3.** The Bati Raman field's production trend [15].

#### **2.5. SECARB**

The Southeast Regional Carbon Sequestration Partnership (SECARB) [17] operated a test for CO2 sequestration at Black Warrior Basin in Alabama from 2006 to 2009 and determined that more than 360 million tons could be sequestered while increasing coalbed methane reserves by more than 20%. The SECARB set up monitoring systems in shallow boreholes and continues to monitor the local soil profile to determine if seepages of their test injection of 1000 tons of CO2 -injected gas occur and to facilitate the development of monitoring protocols that will ensure the safe conduct of CO2 injection activities.

#### **2.6. SWP projects**

The Southwest Regional Partnership for Carbon Sequestration (SWP) indicates that over 2 million metric tons out of a total of 7 million metric tons retained CO2 in the Scurry Area Canyon Reef Operators (SACROC) project were dissolved in the aqueous phase. That report does not include nor report CO2 dissolution in oil, and therefore the numbers for CO2 dissolution in the aqueous phase may be compromised. In addition to CO2 dissolution in oil, the presence of a hydrocarbon phase can limit the contact between injected CO2 and the aqueous phase even in depleted carbonate reservoirs. This work will, therefore, enhance estimates of predicted storage capacity both in depleted and producing oil reservoirs by revisiting and considering CO2 solubility in the oil phase.

Additionally, rock wettability determines whether hydrolyzed CO<sup>2</sup> and the resulting acid in the aqueous phase can come into contact with the rock surface. When the rock is strongly oil wet such as in most carbonates, carbonate dissolution cannot take place; therefore, requirements for the mineralization trapping mechanism will not be met. In that case, the current estimation of CO2 storage capacity in oil reservoirs because of the mineralization mechanism should be revisited. There is no indication of wettability measurement in the SACROC project. The SACROC project seeks to develop a subsurface geochemical-compositional flow model that incorporates the physics learned from lab-based measurements conducted throughout the course of its work, which will add considerably to the body of knowledge for carbonate reservoirs.

#### **2.7. Existing exploited CO2 sources**

The majority of CO2 injected into formation during operations is from natural reservoirs; however, problems arise such as climate change, diminished supply, and large demand. Innovation provides the solution by capturing CO2 previously released to the atmosphere and using it for CO2 EOR. During the production process, produced CO2 is captured at the surface and reinjected, thus trapping the majority of injected CO2 in formation. In Wyoming, natural gas processing plants produce approximately 716 Tcf of CO2 while injecting 705 Tcf [7] in carbonate formations. In Michigan, an existing source of CO2 provides the opportunity for carbonate CO2 EOR in the NPRT; thus, Core Energy is using CO2 emissions for EOR operations exploiting carbonate reef deposits [18]. These examples are helping reduce the emissions that would otherwise be vented to the atmosphere.

#### **2.8. ECBM studies**

Due to the effectiveness of CO<sup>2</sup> EOR and sequestration in coal beds, numerous studies have examined the usage of CO2 sequestration in enhanced coalbed methane (ECBM) fields, and there are many field cases.

Mastalerz et al. [19] studied CO2 sequestration and ECBM in unminable coal seams of the Illinois Basin. They found that approximately 271 billion tons of CO2 could potentially be sequestered in the basin. Moreover, they found that potentially 1.6–4.6 billion tons of CO2 could be sequestered in Illinois Basin coals and 70–280 billion m3 (2.4–9.8 Tcf) of CH4 is potentially recoverable as a result of CO2 ECBM practices. The paper does suggest that volumetric strain due and coal swelling, which causes permeability damage, should be considered in any CCS or CO2 EOR project.

Yu et al. [20] predicted in 2007 that the CO2 sequestration throughout all ECBM projects (existing and potential) in China could result in over 3.751 Tm3 of additionally recoverable methane, with a CO2 sequestration capacity of around 142.67 billion tons.

#### **2.9. Shale storage capacity (the United States and Canada)**

The amount of available storage for CO2 in oil and gas shale is currently unknown, but the vast volumes of shale formations indicate that the storage capacity is significant. A recent report has estimated between 1.85 trillion and 20.5 trillion tons of carbon dioxide storage capacity is available in oil and gas reservoirs just in the Unites States and Canada. These estimates suggest the availability for storing centuries worth of CO2 .

#### **2.10. Additional possible locations and projects**

**2.6. SWP projects**

considering CO2

**2.7. Existing exploited CO2**

The majority of CO2

and using it for CO2

carbonate CO2

**2.8. ECBM studies**

Due to the effectiveness of CO<sup>2</sup>

Mastalerz et al. [19] studied CO2

potentially recoverable as a result of CO2

examined the usage of CO2

there are many field cases.

CO2

does not include nor report CO2

216 Recent Advances in Carbon Capture and Storage

The Southwest Regional Partnership for Carbon Sequestration (SWP) indicates that over 2

Canyon Reef Operators (SACROC) project were dissolved in the aqueous phase. That report

phase even in depleted carbonate reservoirs. This work will, therefore, enhance estimates of predicted storage capacity both in depleted and producing oil reservoirs by revisiting and

aqueous phase can come into contact with the rock surface. When the rock is strongly oil wet such as in most carbonates, carbonate dissolution cannot take place; therefore, requirements for the mineralization trapping mechanism will not be met. In that case, the current estimation of

 storage capacity in oil reservoirs because of the mineralization mechanism should be revisited. There is no indication of wettability measurement in the SACROC project. The SACROC project seeks to develop a subsurface geochemical-compositional flow model that incorporates the physics learned from lab-based measurements conducted throughout the course of its work,

however, problems arise such as climate change, diminished supply, and large demand.

EOR. During the production process, produced CO2

tions exploiting carbonate reef deposits [18]. These examples are helping reduce the emissions

sequestered in the basin. Moreover, they found that potentially 1.6–4.6 billion tons of CO2

dissolution in oil, and therefore the numbers for CO2

injected into formation during operations is from natural reservoirs;

EOR and sequestration in coal beds, numerous studies have

sequestration and ECBM in unminable coal seams of the

ECBM practices. The paper does suggest that

sequestration in enhanced coalbed methane (ECBM) fields, and

in the Scurry Area

dissolution in oil, the

and the resulting acid in the

previously released to the atmosphere

is captured at the

in formation. In Wyoming,

provides the opportunity for

emissions for EOR opera-

could potentially be

is

(2.4–9.8 Tcf) of CH4

while injecting 705 Tcf [7]

and the aqueous

disso-

million metric tons out of a total of 7 million metric tons retained CO2

lution in the aqueous phase may be compromised. In addition to CO2

solubility in the oil phase.

Additionally, rock wettability determines whether hydrolyzed CO<sup>2</sup>

 **sources**

surface and reinjected, thus trapping the majority of injected CO2

in carbonate formations. In Michigan, an existing source of CO2

natural gas processing plants produce approximately 716 Tcf of CO2

Illinois Basin. They found that approximately 271 billion tons of CO2

could be sequestered in Illinois Basin coals and 70–280 billion m3

EOR in the NPRT; thus, Core Energy is using CO2

Innovation provides the solution by capturing CO2

that would otherwise be vented to the atmosphere.

presence of a hydrocarbon phase can limit the contact between injected CO2

which will add considerably to the body of knowledge for carbonate reservoirs.

Depleted oil and gas fields in the SECARB region could provide 29.7–34.7 billion tons of CO<sup>2</sup> storage with 24 million recovered oil barrels [21]. Almost 60% of the estimated volume relate to offshore fields. Coal and organic-rich shale formations can also offer a significant place for storage due to high absorption capacity of CO2 in addition to potential EOR applications. A tertiary coal in the Gulf of Mexico is estimated to have 20–28 billion tons of CO2 storage [18].

The potential storage capacity of the Barnett Shale is estimated to be 19–27 Gton, while other shale formation, Fayetteville Shale, is estimated to be capable of sequestrating 14–20 Gton of CO2 [18]. There are still a lot more fields in the SECARB region to be evaluated on a possibility of a potential CO2 storage and sequestration site. The SECARB region has a large annual CO2 emission from coal-fired power generation and other fossil-fueled plants. In 2008 it was estimated to emit almost 2.9 [22] billion metric tons of CO2 .

An estimation of possible CO2 sequestration volume was done by a "production replacement" principle, where for every volume of hydrocarbon, a 1:1 replacement ratio of CO2 volume takes place. For the 2008 rates of CO2 emission, SECARB region was capable of providing at least 28 years of CO2 storage [18]. A case with a CO2 EOR and sequestration in the Bell Creek oil field has a promising estimation of a recovery of additional 35 [23] million bbl of incremental oil through CO2 flooding. Current plans exist to build a 232-mile pipeline from ConocoPhillips Lost Cabin gas producing plant to the Bell Creek field. This will help to integrate the large-scale storage of over 1 million tons of CO2 per year.

#### **3. Upcoming improvements to field applications**

Kuuskraa, Godec and Dipeitro [24] analyzed primary and enabling next-generation technologies with applications in CO2 sequestration, as shown in **Table 1**, and approximated the benefits of these technologies on a sample field area, as shown in **Table 2**. Notably, using their sample and estimates, they predict an increase in economically recoverable resource from 21.4 to 63.3 billion bbls.


#### **Table 1.** Technologies used in next-generation CO2 EOR [22].


\*At \$90 per barrel oil price and \$40 per metric ton CO2 price, with 20% rate of return (before tax). Results compiled from simulations of CO2 EOR floods at 1800 oil-bearing formations in the onshore continental United States. Reservoir characterization data drawn from the Big Oil Fields database, simulations conducted using the PROPHET stream tube model.

**Table 2.** Results from next-generation CO2 EOR [22].

#### **3.1. Simultaneous injection into pay zones and aquifers for ECBM**

Ahmadi et al. [25] performed numerical modeling to investigate reasonable CO2 injection scenarios, which were applied to CO2 sequestration and ECBM. In their study, the main goal was to study different CO<sup>2</sup> injection methods and the effect of operational factors on the performance of each method by a numerical simulation model. There were three different strategies concentrated, which were soluble and insoluble CO2 injection into the bottom aquifer, CO<sup>2</sup> injection into pay zone, and simultaneous CO2 injection into aquifer and pay zone. The result was that simultaneous injection into aquifer and pay zone leads to higher final oil recovery in EOR schemes.

#### **3.2. Modifications to shale CO<sup>2</sup> processes**

Due to the low porosity of shale, capillary forces are not negligible. Furthermore, adsorption has to be carefully considered due to a large specific area in shale. Pu and Li [26] gave a new formulation that includes the capillary force and adsorption through pore size distribution. A local density optimization algorithm was used to the adsorption model. In the Bakken field, the results of their investigations reduced the soaking time of the CO2 huff "n" puff process and increased the 18% OOIP ultimate recovery.

#### *3.2.1. Shale heterogeneity needs to be considered*

Most of the unconventional reservoirs are heterogeneous, which influences the application of the huff "n" puff method. Chen et al. [27] studied the relationship between the reservoir heterogeneity and CO2 huff "n" puff recovery through running simulations in the Elm Coulee Field of the Bakken. Shale heterogeneity had a significant negative impact, reducing the final recovery rate of the well.

#### *3.2.2. There have not been large-scale CO2 sequestration projects with shale*

Large-scale demonstrations to prove CO2 storage capability and capacity for very long periods of time in shale have not yet occurred [28]. According to Global CCS Institute [29], only 15 large-scale projects on CO2 storage are taking place around the world with CO2 capture capacity volumes ranging from 0.7 to 7 million tons per annum (Mtpa) in countries such as Norway, Algeria, Canada, and the United States. These do not include smaller projects that use CO2 injection and end up sequestering smaller volumes, i.e., CO2 EOR projects.

#### *3.2.3. Improving CO2 sweep efficiency*

**3.1. Simultaneous injection into pay zones and aquifers for ECBM**

EOR [22].

narios, which were applied to CO2

**Table 2.** Results from next-generation CO2

to study different CO<sup>2</sup>

from simulations of CO2

model.

**I. Primary technologies** 1. Improved reservoir conformance

218 Recent Advances in Carbon Capture and Storage

2. Advance CO2

4. Increased volumes of efficiently used CO<sup>2</sup>

5. Near-miscible CO2

**II. Enabling technologies** 1. Robust reservoir characterization

3. Monitoring, diagnostics and control (MDC)

**Table 1.** Technologies used in next-generation CO2

**Resource area Economic oil recovery (billion bbls) \***

\*At \$90 per barrel oil price and \$40 per metric ton CO2

Ahmadi et al. [25] performed numerical modeling to investigate reasonable CO2

mance of each method by a numerical simulation model. There were three different strategies

**Technologies Technology implementation The use of enabling technologies**

from high permeability

 flood pattern; drill additional wells to flood poorly swept

1.5 HCPV; reduce sorm from 0.1 to 0.08

Advanced logging, seismic monitoring

Downhole monitoring systems, realtime diagnostics, smart wells, etc.

EOR [22].

**tons)**

Miscible 19.6 60.8 8.4 15.4 2.3 3.9 Near miscible 1.8 2.6 0.5 0.8 3.9 3.3 Total **21.4 63.3 8.9 16.2 2.4 3.9**

**Demand for CO2**

characterization data drawn from the Big Oil Fields database, simulations conducted using the PROPHET stream tube

**SOA Next generation SOA Next generation SOA Next generation**

max pressure within 80% of MMP; reduce sorm based on reservoir

injection from 1 HCPV to

EOR to oil reservoirs with

Reservoir characterization and MDC

Reservoir characterization and MDC

MDC and enhanced fluid injectivity

Essential for technologies 1 and 2

Essential for technologies 3 and 4

Essential for technologies 1, 2, and 4

 **utilization (bbls/**

**Average CO2**

**mtCO2 )**

price, with 20% rate of return (before tax). Results compiled

Enhanced fluid injectivity

–

 **(billion metric** 

Divert CO2

zone(s)

Increase CO2

pressure

and core analysis

3. Enhanced mobility control Increase viscosity of drive water (WAG) to 2 cp

EOR Apply CO2

2. Enhanced fluid injectivity Effective near-wellbore stimulation methods

flood design Realign CO2

reservoir channels

injection sce-

sequestration and ECBM. In their study, the main goal was

injection methods and the effect of operational factors on the perfor-

EOR floods at 1800 oil-bearing formations in the onshore continental United States. Reservoir

To maximize the effectiveness of CO<sup>2</sup> sequestration and adsorption in shale, it is important for the injected carbon dioxide to come in contact with as much reservoir volume as possible, a phenomenon known as sweep efficiency. Again, not enough CO<sup>2</sup> sequestration projects in shale formations have taken place and been monitored to show what the most effective conditions are to keep carbon dioxide sequestered. An increase in recovery rate from CO2 injection under specified conditions can be used to estimate the optimum requirements to achieve utmost levels of sweep efficiency, but this is not necessarily the ideal condition for sequestration.

The available knowledge suggests recovery factors increase drastically when carbon dioxide is injected around minimum miscible pressure (MMP) that is around 1500 psi [30]. MMP can change by a few percentages depending on reservoir pressure, permeability, heterogeneity, and pore geometry.

One of the advantages of carbon dioxide is that its MMP is much lower than other gases; therefore, CO2 MMP injection is possible under a wide range of reservoir pressures [31]. At around MMP, carbon dioxide and oil are miscible which leads to a zero entry capillary pressure. This allows carbon dioxide to enter the oil filled tight pores of shale and increase sweep efficiency and storage with high displacement efficiency. Also, the required soaking time, the time needed for injected gas to pierce and spread throughout the formation, appears to have a significant effect on sweep efficiency because of exceedingly low permeability of shale formations. Longer shut-in periods after CO2 injection show higher oil recoveries that indicate a greater sweep efficiency [28].

#### **3.3. Carbonate potential**

In the South Sumatera Basin, 98 carbonate oil fields represent 59% of total original oil in place (OOIP) [32]. A study ranked these reservoirs based on CO2 EOR and sequestration.

#### *3.3.1. Challenges in carbonates present opportunities in CCS*

Carbonate hydrocarbon reservoirs remain poorly understood; opposed to other storage sites, carbonates are likely to be hydrophobic (2/3rd of the world's carbonate reservoirs are oil wetting). CO<sup>2</sup> dissolution in the oil phase is orders of magnitude higher than its solubility in brine as seen in **Figures 4** and **5**. In the context of CO2 sequestration in carbonate hydrophobic storage sites, dissolution of CO2 in the oil phase is favorable for the long-term CO2 storage in comparison with free supercritical CO2 storage or CO2 dissolution in brines.

**Figure 4.** Pressure dependence of CO2 dissolution in an oleic phase in 71°C [33].

**Figure 5.** Pressure dependence of CO2 dissolution in water at 65° [34].

#### **4. Economics**

One of the advantages of carbon dioxide is that its MMP is much lower than other gases;

around MMP, carbon dioxide and oil are miscible which leads to a zero entry capillary pressure. This allows carbon dioxide to enter the oil filled tight pores of shale and increase sweep efficiency and storage with high displacement efficiency. Also, the required soaking time, the time needed for injected gas to pierce and spread throughout the formation, appears to have a significant effect on sweep efficiency because of exceedingly low permeability of shale for-

In the South Sumatera Basin, 98 carbonate oil fields represent 59% of total original oil in place

Carbonate hydrocarbon reservoirs remain poorly understood; opposed to other storage sites, carbonates are likely to be hydrophobic (2/3rd of the world's carbonate reservoirs

dissolution in an oleic phase in 71°C [33].

dissolution in the oil phase is orders of magnitude higher than its

MMP injection is possible under a wide range of reservoir pressures [31]. At

injection show higher oil recoveries that indicate a

EOR and sequestration.

sequestration in car-

dissolu-

in the oil phase is favorable for the

storage or CO2

therefore, CO2

mations. Longer shut-in periods after CO2

(OOIP) [32]. A study ranked these reservoirs based on CO2

solubility in brine as seen in **Figures 4** and **5**. In the context of CO2

storage in comparison with free supercritical CO2

*3.3.1. Challenges in carbonates present opportunities in CCS*

bonate hydrophobic storage sites, dissolution of CO2

greater sweep efficiency [28].

220 Recent Advances in Carbon Capture and Storage

**3.3. Carbonate potential**

are oil wetting). CO<sup>2</sup>

**Figure 4.** Pressure dependence of CO2

long-term CO2

tion in brines.

One of the primary challenges facing CCS and CO2 EOR is the cost of trapping and delivering CO2 . Large-scale injection of CO2 , for any purpose, can only reach its full potential when a supply chain and infrastructure are established, and most locations do not have access to a preexisting CO2 infrastructure [16, 35].

For instance, while the impermeable shale barriers in an Illinois Basin are a perfect seal for a long-term sequestration of CO2 , the absence of a CO2 delivery infrastructure, despite local electrical power facilities emitting over 255 [20] metric tons of CO2 annually, still overcomes all the scientific potential in the area. The same scientific potential could allow low-temperature oil reservoirs to become sequestration targets, and to increase the local CO2 storage capacity 20 times, at the same time, to enhance the oil recovery by another 6–18% (360–1100 MMSTB) [21].

In one case in the Gazran field, the costs to acquire CO<sup>2</sup> were approximately 11\$/metric ton, with recycling costs of approximately 8\$/metric ton [16]. In other areas, such as West Texas, prices can be as high as \$40/ton with 18 billion tons of CO2 required, making it very difficult to initiate large-scale CO2 projects without a proper supply chain. Ghomian et al. [36] estimated that the total costs of CO2 sequestration are in the range of \$40–\$60 per ton of CO2 stored, primarily due to the costs of CO2 capture and compression. In cases where a proper CO2 infrastructure can be created, CO2 transported via a pipeline with rates above 10 million tons of CO2 per year often cost less than \$1/metric ton of CO2 per 100 km, with lower flow rates costing as much as double that amount [34]. This suggests that once a basic infrastructure has been created, the capture cost of CO2 will become the limiting factor in CCS and CO2 EOR projects.

#### **4.1. Coal bed**

No matter how efficiently CO<sup>2</sup> ECBM and CO2 sequestration works when CO2 is readily available, economic problems cannot be ignored. Robertson [37] provided the economic analysis of CO2 sequestration and CO2 ECBM of the Powder River Basin in Wyoming. He evaluated three production scenarios (no gas injection, flue gas injection, CO<sup>2</sup> injection). Strategies were analyzed using a discount rate of 10% and the rate of return on investment. A Monte Carlo model was used to analyze the CO2 injection method and the mean value of the CO2 injection scenario (**Figure 6**). It was found that for the mean case, a cost of CO2 of approximately \$4.81/Mg (or \$4.81/metric ton) is required to maintain the economic viability [35].

**Figure 6.** Distribution and mean value of the cost of CO2 separation/capture required to yield a 10% rate of return [35].

Robertson also suggested that separating CO2 from flue gas and injecting it into the unminable coal zones of the Powder River Basin seam, while currently uneconomical, can increase recovery of methane by 17% and could sequester over 86,000 tons CO2 /ac [35].

A 2009 economic analysis by Gonzalez et al. investigated the effectiveness of CO<sup>2</sup> EOR and sequestration on coal beds of different initial permeability values and determined that CO<sup>2</sup> storage was often quite economical on wells of moderate permeability (10 milliDarcy) and high permeability (100 milliDarcy). In their study, none of the low permeability cases were economical. It is worth to mention that high-rank coals (those containing higher levels of carbon) showed the strongest economics [38].

#### **5. Injection and sequestration**

Unlike in the oil industry where the inability to recover injected resources is often a cause for concern and additional economic strain, CCS inherently requires the permanent sequestration of CO2 in the given reservoir. These conflicting intentions will need to be overcome for economic purposes if CCS and CO2 EOR are to become major players in the fight against climate change. Once these challenges have been overcome, the effectiveness with which CO<sup>2</sup> can be sequestered into different formations becomes a major point of importance.

Examples of the effectiveness of CO<sup>2</sup> sequestration are fairly common. Yamaguchi et al. [39] investigated the Ishikari Coalfield in Japan, where a multi-well test was able to inject 600 tons of CO2 with an estimated 96% of the CO2 being successfully adsorbed into the coal bed. Mavor et al. [40] analyzed a project by the Alberta Research Council which operated a two-well pilot test, where they determined that the increase in CO2 injectivity (owing ballooning and water saturation reduction) was able to overcome injectivity losses due to swelling. Results were greatly improved by reducing injection periods, which allowed for adsorbed gas in the coal bed to finish swelling and for CO<sup>2</sup> to diffuse throughout the reservoir. These results were mirrored by Wan and Sheng [41], who determined that in fractured reservoirs, cyclic gas injection could increase oil recovery to 29%, while primary production only produced about 6.5% of OOIP [39].

Sheng and Chen [42] compared CO2 and water flooding and were able to achieve superior results for CO2 injection both in the case of flooding and huff "n" puff scenarios, with the best results (production of 32.46% OOIP) occurring using the huff "n" puff method.

#### **5.1. CO2 EOR in gas condensate wells**

**4.1. Coal bed**

CO2

No matter how efficiently CO<sup>2</sup>

222 Recent Advances in Carbon Capture and Storage

sequestration and CO2

was used to analyze the CO2

ECBM and CO2

production scenarios (no gas injection, flue gas injection, CO<sup>2</sup>

(**Figure 6**). It was found that for the mean case, a cost of CO2

Robertson also suggested that separating CO2

**Figure 6.** Distribution and mean value of the cost of CO2

bon) showed the strongest economics [38].

**5. Injection and sequestration**

tration of CO2

ery of methane by 17% and could sequester over 86,000 tons CO2

\$4.81/metric ton) is required to maintain the economic viability [35].

able, economic problems cannot be ignored. Robertson [37] provided the economic analysis of

lyzed using a discount rate of 10% and the rate of return on investment. A Monte Carlo model

coal zones of the Powder River Basin seam, while currently uneconomical, can increase recov-

sequestration on coal beds of different initial permeability values and determined that CO<sup>2</sup> storage was often quite economical on wells of moderate permeability (10 milliDarcy) and high permeability (100 milliDarcy). In their study, none of the low permeability cases were economical. It is worth to mention that high-rank coals (those containing higher levels of car-

Unlike in the oil industry where the inability to recover injected resources is often a cause for concern and additional economic strain, CCS inherently requires the permanent seques-

in the given reservoir. These conflicting intentions will need to be overcome

A 2009 economic analysis by Gonzalez et al. investigated the effectiveness of CO<sup>2</sup>

injection method and the mean value of the CO2

sequestration works when CO2

ECBM of the Powder River Basin in Wyoming. He evaluated three

is readily avail-

injection scenario

EOR and

injection). Strategies were ana-

of approximately \$4.81/Mg (or

from flue gas and injecting it into the unminable

separation/capture required to yield a 10% rate of return [35].

/ac [35].

Higher densities of CO2 relative to the native gas condensate cause CO2 to migrate downward; with an increase of viscosity, CO2 will displace the hydrocarbon gas phase. CO2 EOR is very effective in light and medium gravity reservoir oils, in addition to being effective at recovery of gas condensates [43]. The dissolution of CO2 into the oil decreases its interfacial tension; this creates a chance for the capillary force to enhance the recovery of the residual oil. This aspect heavily depends on the pressure and thus the depth. The properties of depleted gas/ condensate reservoirs make them favorable for repressurization and enhanced gas recovery using CO2 [41].

## **6. Possible geomechanical problems**

EOR through CO2 sequestration provides great opportunities for improving hydrocarbon recovery and the reduction of the greenhouse effect. Yet there are still problems about CCS that need to be addressed. A study on a pressure-depleted gas reservoir in the southern North Sea provided insight on CO2 sequestration in depleted hydrocarbon reservoirs [60]. Their sequestration led to multiple geomechanical problems during drilling, completion, and CO2 injection.

These depleted reservoirs have a narrow window of drilling mud weights that will not result in reservoir problems, and well completions can be affected by potential solid flow back when the injection of CO2 is interrupted, while the temperature changes near the wellbore can lead to thermal fracturing and reactivation of faults. CO2 sequestration can sometimes require drilling additional injection wells, which can be a problem with a narrow mud weight window because of the increased chance of a wellbore collapse.

The narrow mud weight window can make it nearly impossible to avoid falling out of the ideal range of mud weights, leading to a number of risks and an increase of nonproductive time and additional costs. During the injection stage, if there are problems with CO2 supply, resulting in an interruption of CO2 injection, solids will flow back into the well, resulting in a risk of rock failure or erosion of a pipeline.

Well integrity is the achievement of fluid containment and pressure containment within the well throughout its whole life cycle. The CO2 injection can lead to the corrosion and degradation of the injection tubing, injection casing, and cement and packer material. The trickiest part is keeping the well leak-free. A CO2 sequestration well has to be designed for over 40 years of continued well integrity. Some potential methods of protecting well integrity include the injection of supercritical CO2 fluid, as it is dry and noncorrosive, protecting a well for a much longer period [44]. Usage of supercritical CO2 , unfortunately, increases costs and can increase issues with temperature changes, which can hydraulically and thermally fracture a rock in a near-wellbore region. This risk can be mitigated by keeping the fluid pressure that acts on a caprock outside of its fracturing pressure. Most other well failure problems can be reduced by keeping a well straight instead of inclined [60].

#### **6.1. Offshore leak issues**

Offshore injections of CO<sup>2</sup> for EOR and sequestration lead to alterations and deformations of caprock, affecting seal integrity. A break in a cap rock can result in a large burst of CO<sup>2</sup> from a reservoir and ultimately the seabed. When evaluating long-term caprock integrity, it is important to note the intrinsic caprock properties, chemical conditions at reservoir/caprock interface, and injection-induced pressure perturbation [61].

The caprock properties to look for are fracture normal stiffness, bulk concentration, and carbonate-forming cations. The enhancement or degradation of a caprock is related to the reduction and widening of microfracture apertures. During an injection process, initial mineral trapping takes place, which can have a significant impact on maintaining initial CO<sup>2</sup> injectivity and can delineate and partially self-seal plume boundaries while also reducing caprock permeability. Many CO2 migration and sequestration processes in saline aquifers are equally applicable to CO2 flood EOR in shale-capped water-wet oil reservoirs [21]. The CO2 storage capacity is inverse proportional on reservoir permeability, which, in pure sequestration scenarios with high injection pressure, benefits from an increased storage and delayed migration, providing a noncompromised caprock performance.

Injection could also lead to pressures exceeding the formations natural fracturing pressure, resulting in the reactivation of a fault or the reservoir rock becoming hydraulically and thermally fractured. This creates a potential breach in the caprock that prevents CO2 migration to the surface or flow into an adjacent formation [60]. An injection is followed by a change of reservoir temperatures that result in expansion and contraction of materials and ultimately result in changes of the field stresses, which creates a risk of breaching the caprock over time.

All geomechanical problems impose a great risk on CO2 storage, which means the caprock integrity must be addressed when selecting a storage well site. The sealing efficiency is dependent on many factors, including caprock, well cement, capillary threshold pressure, and chemical reactivity to CO2 . A proper geological evaluation is required to investigate the possible paths for CO2 migration to the surface through the faults and fractures. Well sites with microseismic activity are generally poor candidates for the long-term containment of CO2 . Topography has to be addressed in the same manner, in the case of CO2 leakage; the surface has to be well ventilated to prevent an accumulation of CO2 cloud.

#### **6.2. Risks and examples of CO<sup>2</sup> leakage**

The narrow mud weight window can make it nearly impossible to avoid falling out of the ideal range of mud weights, leading to a number of risks and an increase of nonproductive

Well integrity is the achievement of fluid containment and pressure containment within the

tion of the injection tubing, injection casing, and cement and packer material. The trickiest part

of continued well integrity. Some potential methods of protecting well integrity include the

issues with temperature changes, which can hydraulically and thermally fracture a rock in a near-wellbore region. This risk can be mitigated by keeping the fluid pressure that acts on a caprock outside of its fracturing pressure. Most other well failure problems can be reduced by

of caprock, affecting seal integrity. A break in a cap rock can result in a large burst of CO<sup>2</sup> from a reservoir and ultimately the seabed. When evaluating long-term caprock integrity, it is important to note the intrinsic caprock properties, chemical conditions at reservoir/caprock

The caprock properties to look for are fracture normal stiffness, bulk concentration, and carbonate-forming cations. The enhancement or degradation of a caprock is related to the reduction and widening of microfracture apertures. During an injection process, initial mineral trapping

delineate and partially self-seal plume boundaries while also reducing caprock permeability.

inverse proportional on reservoir permeability, which, in pure sequestration scenarios with high injection pressure, benefits from an increased storage and delayed migration, providing a

Injection could also lead to pressures exceeding the formations natural fracturing pressure, resulting in the reactivation of a fault or the reservoir rock becoming hydraulically and ther-

to the surface or flow into an adjacent formation [60]. An injection is followed by a change of reservoir temperatures that result in expansion and contraction of materials and ultimately result in changes of the field stresses, which creates a risk of breaching the caprock over time.

rity must be addressed when selecting a storage well site. The sealing efficiency is dependent

migration and sequestration processes in saline aquifers are equally applicable

injection, solids will flow back into the well, resulting in a

sequestration well has to be designed for over 40 years

fluid, as it is dry and noncorrosive, protecting a well for a much

for EOR and sequestration lead to alterations and deformations

injection can lead to the corrosion and degrada-

, unfortunately, increases costs and can increase

supply,

injectivity and can

storage capacity is

storage, which means the caprock integ-

migration

time and additional costs. During the injection stage, if there are problems with CO2

resulting in an interruption of CO2

224 Recent Advances in Carbon Capture and Storage

is keeping the well leak-free. A CO2

injection of supercritical CO2

**6.1. Offshore leak issues**

Offshore injections of CO<sup>2</sup>

Many CO2

to CO2

risk of rock failure or erosion of a pipeline.

well throughout its whole life cycle. The CO2

longer period [44]. Usage of supercritical CO2

keeping a well straight instead of inclined [60].

noncompromised caprock performance.

All geomechanical problems impose a great risk on CO2

interface, and injection-induced pressure perturbation [61].

takes place, which can have a significant impact on maintaining initial CO<sup>2</sup>

flood EOR in shale-capped water-wet oil reservoirs [21]. The CO2

mally fractured. This creates a potential breach in the caprock that prevents CO2

Equipment degradation is a big problem in abandoned wells, as well as currently operating wells. Individual wells have to be monitored in order to spot a leakage of CO2 through the annulus of a wellbore. Leakage can result in not only a migration of CO2 to the surface but also a contamination of surrounding reservoirs and aquifers [43]. This can happen because of wellbore expansion and contraction due to temperature and pressure changes.

Nygaard et al. [45] wrote a paper regarding wellbore well leakage and found that 95 out of 1000 wells near Wabamun Lake in Alberta identified as potential leakage pathways caused by an immediate caprock penetration. This sort of issue is common in poorly plugged wells which can leak CO2 at the cement-rock interface or through a cement plug. Any mechanical load during a completion or stimulation can affect the integrity of the cement, in addition to corrosion and chemical reactions near the wellbore. Issues such as those found in this study must be considered during the life and abandonment of well to ensure a reliable seal.

#### **6.3. Actions to prevent future CO2 leakage**

There are multiple options for sealing abandoned wells, but all of them require at least 8 m of cement inside the casing. Most abandoned wells after 1995 have sufficient integrity. In order to improve the seal integrity, it is suggested to remove the casing steel from abandoned wells before the final cement plug, and an injection of the CO<sup>2</sup> -resistant polymer is executed [44]. The cement samples from 30- to 50-year-old wells kept a good sealing integrity and prevented leakage of CO2 , even though they contained a degree of carbonation [10]. It is not suggested to squeeze the cement into an opening in the casing, but a melted alloy can fill most openings, and its expansion will mitigate microfissures [44].

CO2 injection affects the mineralogy and structural heterogeneity of the reservoir, which will have an impact on the porosity, permeability, and storage stability of the well. Better predictions of reservoir response to CO2 injection are a necessary step in the evaluation of possible long-term sequestration of CO2 . A well-proven method for CO2 testing is Hassler cell core testing, but unfortunately, there is no standard protocol for CO2 testing, which can lead to errors in results [10].

#### **6.4. Selection of readings on stress and possible leakage in ECBM wells**

As ECBM reservoirs often do not have a standard caprock to prevent leakage, their long-term viability as CO2 sequestration targets must be carefully considered. Numerous papers have explored this question and are briefly listed and summarized below:


#### **6.5. CO2 monitoring**

Due to the quantities of CO2 being sequestered in large CCS projects and the importance of keeping that CO2 permanently underground, monitoring is a very important part of any CCS project. 3D seismic survey has proven to be effective at monitoring CO<sup>2</sup> storage but is prohibitively expensive. Gasperikova and Hoversten [50] investigated using a combination of gravity inversion, electromagnetic (EM), and amplitude vs. angle (AVA) monitoring analysis to detect changes in CO2 saturation. Gravity inversion detects density changes in the injected layer. EM and AVA can be used to estimate CO2 saturation changes. Macdonald [51] provided field and lab measurements of CO2 using Raman spectroscopy, which improved monitoring of the prevised amounts of CO2 dissolved in reservoir brine. Through the Saptharishi and Makwana [52] study, various monitoring techniques are summarized, which include but are not limited to techniques for coal beds.

#### **6.6. Risks of CO<sup>2</sup> injection, possible failure modes**

Carbon dioxide storage is not a risk-free task. As years go by after CO2 has been injected into a formation, it is possible for the CO2 to begin migrating upward and leak out of the ground back into the atmosphere through openings in the caprock or fractures, faults, and poorly completed preexisting wells [53]. This problem can be prevented or reduced if the formation of interest for CO2 storage has a caprock with ideal qualities.

An ideal caprock is a layer of the formation with very low permeability that can prevent oil and gas from migrating upward and out of the reservoir formation. In any case of CO2 storage, a thick shale layer is the most desirable type of caprock. Due to shale's extremely low permeability, causing a more tortuous flow path, CO<sup>2</sup> migration vertically is tremendously limited [54]. The degradation of cement and metal casing with a presence of CO2 is currently a topic that needs extensive investigation [52]. As the **Figure 7** shows, there are five possible leakage pathways in an abandoned well. Label a and label b are the pathway between casing and cement wall and plug, respectively. Label c shows leakage through cement plugs. Label d represents leakage through casing. Label e shows leakage through the cement wall. Label f represents leakage pathways between the cement wall and the formation [52].

**Figure 7.** CO2 leakage pathways.

• In the report of Myer [46], geomechanical factors that risk CO2

• Mitra and Harpalani [47] investigated the matrix strain resulting from a CO2

• Chen et al. [48] investigated how the effective stress factor and methane CO<sup>2</sup>

permeability loss/gain is influenced by effective stress and methane CO<sup>2</sup>

and that the gas pressure distribution is related to gas composition [47].

project. 3D seismic survey has proven to be effective at monitoring CO<sup>2</sup>

 **injection, possible failure modes**

Carbon dioxide storage is not a risk-free task. As years go by after CO2

permeability, causing a more tortuous flow path, CO<sup>2</sup>

storage has a caprock with ideal qualities.

limited [54]. The degradation of cement and metal casing with a presence of CO2

• Fathi and Akkutlu [49] investigated counter-diffusion and competitive adsorption effects according to the new one-dimensional theoretical model they created. Compared with the conventional model, they created a new triple porosity dual permeability multi-continuum model to describe the gas release from macro-pores and micro-pores to the fracture.

tively expensive. Gasperikova and Hoversten [50] investigated using a combination of gravity inversion, electromagnetic (EM), and amplitude vs. angle (AVA) monitoring analysis to detect

[52] study, various monitoring techniques are summarized, which include but are not limited

back into the atmosphere through openings in the caprock or fractures, faults, and poorly completed preexisting wells [53]. This problem can be prevented or reduced if the formation

An ideal caprock is a layer of the formation with very low permeability that can prevent oil and gas from migrating upward and out of the reservoir formation. In any case of CO2

age, a thick shale layer is the most desirable type of caprock. Due to shale's extremely low

a topic that needs extensive investigation [52]. As the **Figure 7** shows, there are five possible leakage pathways in an abandoned well. Label a and label b are the pathway between casing

well as the risk of CO2

226 Recent Advances in Carbon Capture and Storage

fusion work on the CO2

 **monitoring**

Due to the quantities of CO2

and lab measurements of CO2

prevised amounts of CO2

to techniques for coal beds.

EM and AVA can be used to estimate CO2

a formation, it is possible for the CO2

**6.5. CO2**

keeping that CO2

changes in CO2

**6.6. Risks of CO<sup>2</sup>**

of interest for CO2

tion, gas flow, and methane-CO<sup>2</sup>

tion, are discussed.

leakage in sequestration, as

injection.

counter-diffusion

storage but is prohibi-

has been injected into

migration vertically is tremendously

stor-

is currently

counter-dif-

leakage from drilling and completion, production, and repressuriza-

recovery using a finite element model that coupled coal deforma-

being sequestered in large CCS projects and the importance of

using Raman spectroscopy, which improved monitoring of the

dissolved in reservoir brine. Through the Saptharishi and Makwana

saturation changes. Macdonald [51] provided field

to begin migrating upward and leak out of the ground

permanently underground, monitoring is a very important part of any CCS

saturation. Gravity inversion detects density changes in the injected layer.

counter-diffusion. Through their study, it was found that

The Sleipner Project, located in Norway, is currently storing more than 2700 tons of CO2 per day below an extensive and thick shale layer [27]. Monitoring the injected CO2 during the past 13 years is showing that the gas has spread out nearly two square miles below the shale layer without moving upward or leaking out of the reservoir storage [55]. This is one of the most significant evidence that proves how effective shale formations can be as CO<sup>2</sup> storage reservoir and caprock, where carbon dioxide will be trapped and immobile. In short, the ultimate geological storage reservoir should have sufficient capacity, be a thick shale layer acting as a caprock simultaneously, and be a stable storage environment maintaining the original characteristics of the reservoir.

#### *6.6.1. Overcoming the high risk of CO2 leakage in carbonate reservoirs*

Carbonate reservoirs do not generally possess an impermeable boundary or caprock, and therefore permanent trapping of CO2 through geomechanical means is unrealistic [57]. Solubility storage decreases potential leakage in carbonate formations, as the dissolution of CO2 into water promotes mineralization, but this will need to be studied further before carbonate reservoirs can be relied upon to properly sequester large volumes of CO2 [56].

Agada et al. [57] did extensive research on how fracture network geometry affected oil recovery and CO2 storage in carbonate reservoirs. They noted that many of the problems associated with high fracture-matrix connectivity, such as bypassing of oil, early water breakthrough, and rapid CO2 migration, could be mitigated by foam flooding. Sehbi et al. [58] proposed a low injection rate, longer in-reservoir CO2 retention time, and good pore structure to improve the efficiency in carbonate reservoirs. Carbonate formations showed an increase in effective permeability resulting from chemical dissolution in the matrix, thus enhancing pore connectivity [59].

#### *6.6.2. Examples of natural carbonate sequestration*

The Colorado Plateau-Southern Rocky Mountains region contains natural CO2 , which has been discovered during exploration for oil and gas fields (**Figure 8**), thus providing a natural laboratory for studying the effects of long-term, subsurface CO<sup>2</sup> storage in carbonate reservoirs. These laboratories yield information such as that injecting CO2 separated from flue gases ensures the subsurface migration path is long, thereby yielding optimal sequestration. Despite the number of carbonate CO2 reservoirs in the region and active flux of CO<sup>2</sup> to the surface, no hazards from CO2 surface accumulations are known. The nature and rate of CO2 surface leakage in carbonate formations are still unknown [60].

**Figure 8.** Synthesis of data relating to CO2 fluxes and concentrations around the Colorado Plateau [8].

#### **6.7. Additional potential concerns**

Despite the many benefits of CO<sup>2</sup> EOR and CCS programs, it must be remembered that these are complicated projects being undertaken in complex geological environments. A 2004–2008 project in Algeria stored over 2.5 [61] million tons of CO2 in a carboniferous sandstone reservoir. During the shut-in process, the CO2 injection was unexpectedly interrupted, and the wellbore pressure went lower than the reservoir pressure, risking rock failure, sand production, and possible blowout.

Potential concerns also include preventing potentially catastrophic failure of the reservoir seal. For instance, if injection pressures exceed the breakthrough pressure of the sealing caprock, the CO2 would break through and risk flowing back to the surface [60]. Reactive transport modeling shows that for a typical shale caprock, geochemical processes continuously improve isolation performance, and geomechanical processes first rapidly degrade and then improve isolation performance over time. There is a possibility for a counterbalancing of geomechanical and geochemical effects, but they must be carefully monitored [62].

Some issues are more minor, not directly threatening the safety of the operation, but nonetheless affecting the economics of a combined CO<sup>2</sup> EOR and CCS project. Bou-Mikael [14] wrote about the performance of a CO2 flood at Port Neches in the Gulf of Mexico, with a partnership of Department of Energy and Texaco E&P. The CO2 flood underperformed [13], with 500 bbl/day instead of 800 bbl/day; with this underperformance was attributed to the following reasons: reservoir characterization, oil saturation, water blockage, and wellbore mechanical problems. After a careful evaluation of the project, it was determined that in ideal circumstances and if related criteria are met, CO2 injection can accelerate production two to three times compared to unassisted primary production [13].

#### *6.7.1. Potential coalbed problems*

*6.6.2. Examples of natural carbonate sequestration*

Despite the number of carbonate CO2

**6.7. Additional potential concerns**

**Figure 8.** Synthesis of data relating to CO2

Despite the many benefits of CO<sup>2</sup>

surface, no hazards from CO2

228 Recent Advances in Carbon Capture and Storage

The Colorado Plateau-Southern Rocky Mountains region contains natural CO2

laboratory for studying the effects of long-term, subsurface CO<sup>2</sup>

surface leakage in carbonate formations are still unknown [60].

voirs. These laboratories yield information such as that injecting CO2

been discovered during exploration for oil and gas fields (**Figure 8**), thus providing a natural

gases ensures the subsurface migration path is long, thereby yielding optimal sequestration.

reservoirs in the region and active flux of CO<sup>2</sup>

EOR and CCS programs, it must be remembered that these

fluxes and concentrations around the Colorado Plateau [8].

are complicated projects being undertaken in complex geological environments. A 2004–2008

surface accumulations are known. The nature and rate of CO2

, which has

to the

storage in carbonate reser-

separated from flue

Coal beds, despite offering unique opportunities, also offer unique challenges. In particular the coal matrix swells during CO2 adsorption. Coal matrix swelling can cause reductions in permeability. Bustin et al. [63] experimented on the volumetric strain from three western Canadian coals and found that a mixture of N2 and CO2 injection would improve CO2 injection rates greatly but that CO2 sequestration capacity decreased wildly. However, pure CO2 injection could cause the reduction of permeability by two orders of magnitude. The applicability of the CO2 -ECBM process in any coal seam is mainly governed by the seam's permeability and its adsorption process [62]; therefore, these concerns must be explored further.

#### **7. Conclusion**

Numerous studies support the potential of major sequestration projects, and due to the negative impacts of atmospheric CO2 , CCS will continue to be an important part of protecting our environment. While EOR through CO2 sequestration has proved to be valuable, there are still challenges that need to be addressed in the future. Reservoir properties must continue to be carefully considered for all CCS projects due to their impact on successful EOR and CO2 sequestration.

The major challenges currently facing CCS projects are primarily those of economics and transportation. Limited CO2 transportation supply chains act as a barrier for CO2 EOR utilization in the oil industry. When this barrier has been removed and a large network of CO2 capturing mechanisms have been created, it will open the petroleum industry to a breadth of new possibilities both in terms of improved recovery and environmental sustainability.

For the purposes of having a significant impact on atmospheric CO<sup>2</sup> levels, the simple merging of CO2 EOR and CCS may not be enough. In every reservoir type, in every circumstance, there are diminishing returns as far as incremental production as additional CO2 is injected into a well. As such, as long as CO2 remains an expense, rather than a revenue stream, the full potential of CCS will not be realized. In the meantime, however, there are numerous projects that hold a good deal of promise and are economical under current conditions due to the benefits of CO<sup>2</sup> injection on ultimate hydrocarbon recovery.

#### **7.1. Closing notes on shale reservoirs**

Shale reservoirs still hold a great deal of promise for CCS and CO2 EOR, as the benefits for production are significant, and the formations themselves provide excellent seals against any risk of CO2 migration. Unfortunately, a great deal of research and monitoring is still required in order to ensure that shale beds maintain the quality of their seals over time and to maximize CO2 sequestration. Knowledge gaps such as lack of information on available storage capacity, lack of formation and reservoir data that specifies favorable sequestration settings, understanding long-term CO<sup>2</sup> interaction in shale, and testing different strategies for CO2 injection and well patterns to achieve efficient carbon dioxide sequestration and EOR still exist [52]. Many questions regarding this topic will remain unanswered until additional, large, in situ field tests take places.

#### **7.2. Closing notes on carbonate reservoirs**

The future of CO2 EOR and sequestration in carbonate reservoirs will steadily improve due to the statistical data being acquired from existing field tests. The United States' carbonate formations provide the foundation for CO2 injection in carbonate reservoirs [64]. The Bati Raman reservoir provides a significant opportunity to further carbonate CO<sup>2</sup> EOR operations. Sahin et al. [65] state this reservoir could easily yield a billion dollars in revenue as a CO2 EOR project. Hydrocarbon fuels can supply relatively pure CO2 for EOR allowing the byproducts of the industry's previous production to add in new production while also creating a more environmentally friendly outcome. CO2 that cannot be used for EOR can be stored in depleted carbonate formations, thus furthering the climate-friendly initiative [66]. Recent estimates of future CO2 demand suggest that large volumes will be required to meet the promise of nextgeneration EOR including the development of residual oil zones [7].

#### *7.2.1. Specific challenges in carbonate reservoirs*

As previously discussed, dissolved CO2 injection is recommended for reactive fractured formations and formations with uncertain caprock integrity [7]. The challenges of the carbonate pinnacle reef data analysis are as follows: an increase in pressure with CO2 injection, the presence of multiple reservoir fluids, and unique CO<sup>2</sup> phase behavior due to changing pressure and temperature.

Izgec et al. [1] discuss challenges of mineral trapping, the effects of changing rock properties, and the residual impact on CO2 CCS in carbonate reservoirs. Puon et al. [67] state that other challenges in carbonate formations include CO2 tendency to bypass a large percentage of pore volume, yielding an early breakthrough, and reductions in recovery efficiency. As a result, CO2 flooding is not economically feasible without improved mobility control. Several mobility control methods have been attempted with limited success; therefore, concepts for CO2 mobility control are required to increase the overall recovery efficiency and economics in carbonate reservoirs [66]. Eke et al. [8] suggested the injection of denser CO2 saturated brine in carbonate formations, which should be capable of eliminating much of buoyancy force. Thus, CO2 brine surface mixing strategy is recommended due to the enhancement and secure storage of CO2 in subsurface carbonate formations.

#### **8. Suggestions for future study**

in the oil industry. When this barrier has been removed and a large network of CO2

there are diminishing returns as far as incremental production as additional CO2

injection on ultimate hydrocarbon recovery.

Shale reservoirs still hold a great deal of promise for CCS and CO2

sibilities both in terms of improved recovery and environmental sustainability.

For the purposes of having a significant impact on atmospheric CO<sup>2</sup>

ing of CO2

benefits of CO<sup>2</sup>

any risk of CO2

to maximize CO2

The future of CO2

future CO2

for CO2

into a well. As such, as long as CO2

230 Recent Advances in Carbon Capture and Storage

**7.1. Closing notes on shale reservoirs**

settings, understanding long-term CO<sup>2</sup>

**7.2. Closing notes on carbonate reservoirs**

formations provide the foundation for CO2

environmentally friendly outcome. CO2

*7.2.1. Specific challenges in carbonate reservoirs*

As previously discussed, dissolved CO2

project. Hydrocarbon fuels can supply relatively pure CO2

generation EOR including the development of residual oil zones [7].

large, in situ field tests take places.

mechanisms have been created, it will open the petroleum industry to a breadth of new pos-

potential of CCS will not be realized. In the meantime, however, there are numerous projects that hold a good deal of promise and are economical under current conditions due to the

production are significant, and the formations themselves provide excellent seals against

required in order to ensure that shale beds maintain the quality of their seals over time and

storage capacity, lack of formation and reservoir data that specifies favorable sequestration

still exist [52]. Many questions regarding this topic will remain unanswered until additional,

to the statistical data being acquired from existing field tests. The United States' carbonate

of the industry's previous production to add in new production while also creating a more

carbonate formations, thus furthering the climate-friendly initiative [66]. Recent estimates of

mations and formations with uncertain caprock integrity [7]. The challenges of the carbonate

pinnacle reef data analysis are as follows: an increase in pressure with CO2

demand suggest that large volumes will be required to meet the promise of next-

Sahin et al. [65] state this reservoir could easily yield a billion dollars in revenue as a CO2

Raman reservoir provides a significant opportunity to further carbonate CO<sup>2</sup>

injection and well patterns to achieve efficient carbon dioxide sequestration and EOR

migration. Unfortunately, a great deal of research and monitoring is still

sequestration. Knowledge gaps such as lack of information on available

EOR and sequestration in carbonate reservoirs will steadily improve due

EOR and CCS may not be enough. In every reservoir type, in every circumstance,

remains an expense, rather than a revenue stream, the full

interaction in shale, and testing different strategies

injection in carbonate reservoirs [64]. The Bati

that cannot be used for EOR can be stored in depleted

injection is recommended for reactive fractured for-

for EOR allowing the byproducts

capturing

is injected

levels, the simple merg-

EOR, as the benefits for

EOR operations.

injection, the

EOR

For sandstone and coalbed reservoirs, the last major remaining barrier to large-scale implementation of CO2 EOR and CCS is the economic burden of CO2 capture and transportation. Research into improving capture and transport techniques, as well as how to structure intelligent government incentives, will go a long way in increasing CO2 sequestration rates.

Unlike with sandstone and coalbed reservoirs, the primary barrier to CO2 sequestration in shale reservoirs is a lack of research and monitoring work after CO2 injection. The lack of research is in fact only aggravated by the lack of monitoring and in situ data.

At last, the study of CO2 sequestration in carbonate reservoirs needs to expand to include the effects of CO<sup>2</sup> on carbonate rock properties. Issues ranging from an early breakthrough, to low sweep efficiency, to structural problems within the formation, all, limit the viability of large-scale carbonate projects. Future experiments will need to be performed using a highpressure carbonate core flooding system optimized for use within different lab apparatus so that experiments can be conducted to better understand the complications and benefits of supercritical CO2 [57].

There is no doubt that CCS and CO2 EOR/ECBM will play a major role in the future of the energy industry. However, besides the economic issues with many CO2 implementations, legal risks must also be considered as well. Unitization is important for CO2 EOR in order to avoid the trespass claim [68]. In addition, different states and regulators treat CO<sup>2</sup> differently, sometimes as a pollutant, other times as a natural gas [67]. Despite not being research-based concerns, the legal climate of the United States must also change for a truly successful CCS program to take hold and to make the best use of what could become a CO2 revolution.

## **Nomenclature**

