Signiﬁcance of Enhanced Oil Recovery in Carbon Dioxide Emission Reduction

: Limiting the increase in CO 2 concentrations in the atmosphere, and at the same time, meeting the increased energy demand can be achieved by applying carbon capture, utilization and storage (CCUS) technologies, which hold potential as the bridge for energy and emission-intensive industries to decarbonization goals. At the moment, the only proﬁtable industrial large-scale carbon sequestration projects are large-scale carbon dioxide enhanced oil recovery (CO 2 -EOR) projects. This paper gives a general overview of the indirect and direct use of captured CO 2 in CCUS with a special focus on worldwide large-scale CO 2 -EOR projects and their lifecycle emissions. On the basis of scientiﬁc papers and technical reports, data from 23 contemporary large-scale CO 2 -EOR projects in different project stages were aggregated, pointing out all the speciﬁcities of the projects. The speciﬁcities of individual projects, along with the lack of standardized methodologies speciﬁc for estimating the full lifecycle emissions resulting from CO 2 -EOR projects, pose a challenge and contribute to uncertainties and wide ﬂexibilities when estimating emissions from CO 2 -EOR projects, making the cross-referencing of CO 2 -EOR projects and its comparison to other climate-mitigation strategies rather difﬁcult. Pointing out the mentioned project’s differentiations and aggregating data on the basis of an overview of large-scale CO 2 -EOR projects gives useful information for future work on the topic of a CO 2 -EOR project’s lifecycle emissions.


Introduction
The Paris Agreement came into force in 2016 with the intention of mitigating global warming by keeping the global average temperature increase under 2 • C, and preferably even under 1.5 • C, when compared to pre-industrial levels. The only way to do this is through full harmonization with the energy and climate targets, which are comprised of a significant reduction of greenhouse gas emissions by 2030 (by 45%), as well as total decarbonization by 2050, based on the application of energy efficiency, renewable energy use and carbon capture and storage (CCS), or carbon capture, utilization and storage (CCUS). CCS technology implies avoiding CO 2 emissions to the atmosphere by capturing and storing it in geological formations characterized with long-term containment capability [1,2]. As per the strategies submitted to the United Nations Framework Convention on Climate Change (UNFCCC), CCUS is often recognized as a favorable option to fight climate change due to the turning of unwanted greenhouse gas into valuable products [3]. In order to be reused for various purposes (used for yield boosting or for the production of fuels, chemicals, building materials, etc.) CO 2 is captured from different sources, such as fossil fuel-based power plants, ammonia production plants, biomass fermentation facilities, natural gas processing plants, or it can be captured (removed) directly from the air. The commercial-industrial source of CO 2 should be at least 0.01 to 0.5 Mt CO 2 /year [3,4].  [3,15].

CO 2 Source
Use of Captured CO 2 Application Used CO 2 (Mt/y)

CO 2 Conversion
CO 2 conversion includes different kinds or purposes of conversion, such as yield boosting, chemicals, fuels and building materials. They are briefly described below.
Yield Boosting. The largest usage of captured CO 2 is by the fertilizer industry (about 130 Mt/y) for urea production, followed by the petroleum industry (about 80 Mt/y), where CO 2 is used for EOR purposes. The rest of the captured CO 2 serves as feedstock for different industries; for instance: food and drink industries use CO 2 as a carbonating Sustainability 2021, 13, 1800 4 of 27 agent, preservative and solvent for flavor extraction, etc. Another option for CO 2 use is CO 2 -based chemical production. Carboxylation reactions use CO 2 (it replaces a part of the fossil fuel-based raw material) as a precursor for polymer-forming, while reduction reactions produce chemicals by breaking C = O bonds [3].
Chemicals. CO 2 -based synthetic fuels may refer to methane, methanol, gasoline, and aviation fuels. CO 2 captured at power plant exhausts could be used directly in catalytic processes for the generation of synthetic gas. Syngas, as a mixture of CO and H 2 , is a crucial component in the production of hydrogen, ammonia, methanol, and synthetic hydrocarbon fuels. As an intermediate, it can be used in the production of synthetic petroleum by the Fischer-Tropsch process [1,16].
Fuels. The synthetic fuel generation process uses CO 2 and hydrogen to produce a carbon-based fuel, which is, due to easier handling, used in aviation. CO 2 conversion into methanol has a wide range of use (as a fuel, fuel additive or an intermediate for plastics, textiles, and other products) [10,[17][18][19][20][21]. However, among all the above-mentioned CO 2 -based chemical production processes, only polymer production is market competitive due to its relatively low-energy intensity and high product market prices. On the other hand, the costs of synthetic fuel production are uncompetitively high, given that the chemical conversion of CO 2 and pure hydrogen production are energy-intensive. Another disadvantage of CO 2 -based fuels is their short life span, which means that CO 2 is reemitted very quickly into the atmosphere.
Building materials. Besides the options where CO 2 can react with minerals to form carbonates for building materials, it can also be used in concrete production, as a part of cement, aggregate (sand, gravel or crushed stone), or instead of water for concrete curing. Nevertheless, the huge costs per ton of used CO 2 are still not encouraging [3].

Direct Use of CO 2
Significant direct use of CO 2 refers to its underground injection, which may refer to (1) enhanced oil recovery (EOR), (2) enhanced coalbed methane recovery (ECBM), (3) enhanced gas recovery (EGR), (4) enhanced shale gas recovery (ESG), an enhanced geothermal system (EGS) and (6) a supercritical CO 2 power cycle [21]. Injected CO 2 serves as a solvent for residual oil production (EOR). In EGR projects, it pushes natural gas to the production wells, while in ECBM projects, desorption/adsorption processes are crucial for the displacement of methane with CO 2 in the coalbed ( Figure 1) [22,23]. When injected into reservoirs, CO 2 participates in enhancing hydrocarbon recovery through different mechanisms, such as maintaining pressure, multi-contact miscible displacement, molecular diffusion, or the desorption of methane. The injection of CO 2 in a supercritical state into the reservoirs decreases oil viscosity and improves its flow rate (a miscible CO 2 process) or simply pushes the remaining oil (an immiscible CO 2 process) [24,25]. Gas processing facility or industrial sources of CO2 CO2 injection pump CO2 CO2 Figure 1. Carbon capture, utilization and storage (CCUS) technology-underground injection of CO2 [26].
Conventional, water-based EGS requires huge water quantities for maintaining the reservoir's pressure (870. 898.68 L/MWh). Furthermore, about 10-20% of water is lost during EGS stimulation and operation, posing an issue, especially in water scarcity areas [27,28]. Since 2000, the use of SCCO2 as an alternative working fluid was proposed [29], numerous studies on the feasibility and extraction efficiency of the CO2-based systems have been conducted [27,30,31].
CO2 is non-toxic and noncombustible, and therefore convenient for use as a working fluid in enhanced geothermal systems (EGS). This geothermal energy concept uses supercritical CO2 instead of water to produce heat from deep, dry and impermeable rocks. Such a system is composed of a binary-cycle power plant, which operates based on heat exchange from the hot supercritical fluid (CO2) to a secondary working fluid used in a vapor cycle. There are many advantages of using CO2 as a working fluid in geothermal systems instead of water. Besides the benefits of water savings and CO2 sequestration, CO2 is less prone to dissolve minerals and other substances, having a positive impact on scaling and corrosion reduction. The high density of the supercritical CO2 allows for a reduction of most of the system's components, resulting in a decrease of the environmental footprint and capital costs [32,33].
Power generation by the supercritical Brayton cycle (S-CO2 BC) is a promising alternative to the steam turbine process. Up to now, research on the integration of different heat sources (including fossil fuels, nuclear, waste heat, and renewables) has been performed, and there are some small-scale pilot units in operation. Although there have not been any commercial S-CO2 power plant installed up to now, low operational and maintenance costs, a small physical footprint, and higher thermal-to-electric energy conversion efficiency (density of a supercritical fluid is close to that of a liquid, and therefore allows for less pumping power) are listed as the main technological advantages [34,35].
There is a significant geothermal potential of hot dry rocks (HDR). Theoretical calculations showed that a 20 °C reduction of 1 km 3 of HDR provides enough energy to operate a 10 MWe electric generator over a 20 year period, which is equivalent to 1.3 Mt of oil [27]. Although supercritical CO2 technology does not have a commercial application thus far, strong climate-energy goals and a strong commitment to renewables can be a trigger for Conventional, water-based EGS requires huge water quantities for maintaining the reservoir's pressure (870. 898.68 L/MWh). Furthermore, about 10-20% of water is lost during EGS stimulation and operation, posing an issue, especially in water scarcity areas [27,28]. Since 2000, the use of SCCO 2 as an alternative working fluid was proposed [29], numerous studies on the feasibility and extraction efficiency of the CO 2 -based systems have been conducted [27,30,31]. CO 2 is non-toxic and noncombustible, and therefore convenient for use as a working fluid in enhanced geothermal systems (EGS). This geothermal energy concept uses supercritical CO 2 instead of water to produce heat from deep, dry and impermeable rocks. Such a system is composed of a binary-cycle power plant, which operates based on heat exchange from the hot supercritical fluid (CO 2 ) to a secondary working fluid used in a vapor cycle. There are many advantages of using CO 2 as a working fluid in geothermal systems instead of water. Besides the benefits of water savings and CO 2 sequestration, CO 2 is less prone to dissolve minerals and other substances, having a positive impact on scaling and corrosion reduction. The high density of the supercritical CO 2 allows for a reduction of most of the system's components, resulting in a decrease of the environmental footprint and capital costs [32,33].
Power generation by the supercritical Brayton cycle (S-CO 2 BC) is a promising alternative to the steam turbine process. Up to now, research on the integration of different heat sources (including fossil fuels, nuclear, waste heat, and renewables) has been performed, and there are some small-scale pilot units in operation. Although there have not been any commercial S-CO 2 power plant installed up to now, low operational and maintenance costs, a small physical footprint, and higher thermal-to-electric energy conversion efficiency (density of a supercritical fluid is close to that of a liquid, and therefore allows for less pumping power) are listed as the main technological advantages [34,35].
There is a significant geothermal potential of hot dry rocks (HDR). Theoretical calculations showed that a 20 • C reduction of 1 km 3 of HDR provides enough energy to operate a 10 MWe electric generator over a 20 year period, which is equivalent to 1.3 Mt of oil [27]. Although supercritical CO 2 technology does not have a commercial application thus far, strong climate-energy goals and a strong commitment to renewables can be a trigger for its development and application. Cost-benefit analysis based on its CO 2 storage capacity, Sustainability 2021, 13, 1800 6 of 27 power production and the costs of the heat extraction and energy conversion systems could give a solid base for further development phases.
Another use of CO 2 is in preserving fruits, vegetables, meats, food grains, as well as inactivating microorganisms and extracting oils, flavors, colors, chemicals, etc. [36].

Enhanced Oil Recovery by Injecting CO 2
The first step of CCS is to extract CO 2 from other gaseous substances. CO 2 can be captured from natural gas (if it comes from a CO 2 rich oil or natural gas reservoir) using absorption, adsorption, chemical looping, or membrane gas separation, or it can be captured from flue gases at large CO 2 point sources (power plants and industrial processes) by one of the following three methods: pre-combustion capture, post-combustion capture and oxyfuel combustion. Once captured, CO 2 is dehydrated and prepared for transport. It is transported by pipelines, trucks, or ships in a supercritical state to the storage site. Currently, globally operating CCS projects and CCS projects under construction stand for around 40 × 10 6 tCO 2 /y [37].
Today's main applications of CO 2 usage refer to CCS and CO 2 -EOR projects [38]. Even though the two process types consist of the same phases (CO 2 capture, transport, and injection; see Figure 2), they differentiate by injection purpose, storage preservation, injection depth and rate, injection-formation type, injection well completion and monitoring. its development and application. Cost-benefit analysis based on its CO2 storage capacity, power production and the costs of the heat extraction and energy conversion systems could give a solid base for further development phases. Another use of CO2 is in preserving fruits, vegetables, meats, food grains, as well as inactivating microorganisms and extracting oils, flavors, colors, chemicals, etc. [36].

Enhanced Oil Recovery by Injecting CO2
The first step of CCS is to extract CO2 from other gaseous substances. CO2 can be captured from natural gas (if it comes from a CO2 rich oil or natural gas reservoir) using absorption, adsorption, chemical looping, or membrane gas separation, or it can be captured from flue gases at large CO2 point sources (power plants and industrial processes) by one of the following three methods: pre-combustion capture, post-combustion capture and oxyfuel combustion. Once captured, CO2 is dehydrated and prepared for transport. It is transported by pipelines, trucks, or ships in a supercritical state to the storage site. Currently, globally operating CCS projects and CCS projects under construction stand for around 40 × 10 6 tCO2/y [37].
Today's main applications of CO2 usage refer to CCS and CO2-EOR projects [38]. Even though the two process types consist of the same phases (CO2 capture, transport, and injection; see Figure 2), they differentiate by injection purpose, storage preservation, injection depth and rate, injection-formation type, injection well completion and monitoring.

Separation of Industrial Process Gas Streams
Oxy-Firing Flue Gas Separation Gasification or Parrtial Oxidation  Figure 2. Carbon capture and storage (CCS) value chain. Modified according to [39].
Permanent storage of the injected CO2 is provided by a carefully selected geological formation, which must meet certain criteria, among which the significant injection capacity and the presence of impermeable cap rock and bedrock (natural trap) are of the utmost importance [40][41][42][43][44][45][46].
In Croatia, the first application of CO2-EOR was started in October 2014 by the oil company INA-Oil Industry Ltd. The aim of the project was the enhancement of hydrocarbon production by alternating the injection of carbon dioxide and water (WAG) into the mature oil fields Žutica and Ivanić. During the estimated 25-year project's lifetime, about 5 × 10 9 m 3 of CO2 will be injected into the reservoirs of the mentioned fields, which Permanent storage of the injected CO 2 is provided by a carefully selected geological formation, which must meet certain criteria, among which the significant injection capacity and the presence of impermeable cap rock and bedrock (natural trap) are of the utmost importance [40][41][42][43][44][45][46].
In Croatia, the first application of CO 2 -EOR was started in October 2014 by the oil company INA-Oil Industry Ltd. The aim of the project was the enhancement of hydrocarbon production by alternating the injection of carbon dioxide and water (WAG) into the mature oil fields Žutica and Ivanić. During the estimated 25-year project's lifetime, about 5 × 10 9 m 3 of CO 2 will be injected into the reservoirs of the mentioned fields, which will result in additional hydrocarbon production (3.4 × 10 6 t of oil and 599 × 10 6 m 3 of natural gas). Due to geological and physical conditions, about 50% of the injected CO 2 Sustainability 2021, 13, 1800 7 of 27 will remain permanently trapped in the reservoirs, while the rest will be produced along with associated gas [2]. CO 2 injection into the Ivanić field during the period 2014-2019 has resulted in a total hydrocarbon production of 1,579,429 barrels of oil equivalent (boe), which represents a 35% recovery increase. The injection of CO 2 into the Žutica field started in 2015. It has increased daily production by more than 7.5 times, resulting in a total hydrocarbon production of 390,136 boe. According to estimations, 77% of the production can be attributed to the EOR project. For EOR purposes on both fields, 1 billion m 3 (1.98 Mt) of CO 2 was injected within the five-year period. Permanently stored emission quantities are equivalent to 25% of annual emissions of road motor vehicles in Croatia [47][48][49].
An additional advantage of CO 2 -EOR projects is the fact that, once the project is completed, the site can be used for further injection for the purpose of permanent CO 2 sequestration, without additional investment. A calculation of the CO 2 volume that can be stored in the two selected reservoirs of the Ivanić field in Croatia was made within the MBAL (Material Balance) program module of the IPM (Integrated Production Modeling) petroleum engineering software package [50]. Such a model considered the injection of CO 2 after the termination of the EOR project (predicted EOR project closure pressure is 138.5 bar) up to the level of the initial reservoir pressure (184 bar). The obtained capacity was at the level of 1.95 × 10 9 m 3 (3.9 Mt) of CO 2 ( Figure 3). Although the estimated capacity is not big compared to the large world CCS demonstration projects capacities, considering the national emissions of the Republic of Croatia (as per the national Report on the projection of greenhouse gas emissions, CO 2 eq emissions in 2020 are 23.42 Mt), the obtained storage capacity is not negligible [51].   In 2020, more than 375 EOR projects were in operation ( Figure 5), accounting for about 2% of the global oil production (more than 2 × 10 6 bbl/d). There are also good forecasts for the mentioned technology for the future since it is expected that by 2040, this share could double [23]. Although EOR application commenced in North America, recently, EOR technologies are being applied worldwide: in Malaysia, the United Arab Emirates, Kuwait, Saudi Arabia, India, Colombia, Ecuador, etc. While in 2013, almost 70% of the EOR projects were conducted in North America, today, this proportion has decreased to about 40% [53]. CO 2 -EOR and residual oil zone studies are under preparation by the US Geological Survey (USGS). Their purpose is the assessment of the national potential of hydrocarbons recovery after CO 2 injection into conventional oil reservoirs in the USA [54].

Large-Scale CO 2 -EOR Case Studies
As per the KAPSARC data source, in 2018, there were 23 CO 2 -EOR large-scale projects in different project stages, having a CO 2 capture capacity of approximately 42 Mt ( Table 2 [14]). As per the Global CCS Institute, a large-scale project is defined as a project with a capture capacity of at least 0.8 Mt/y of CO 2 for a coal-based power plant and 0.4 Mt/y for other industrial facilities [37].  Figure 5 shows project distribution according to related industries and capacity. Progress in project application can be tracked since the early 1970s ( Figure 6).
A great majority of the ongoing projects (81%) in 2018 were in the USA and Canada, mostly using CO 2 from natural gas processing (Table 2; Figures 5 and 6). Regarding CO 2 -EOR projects related to power generation, besides one operational project (Boundary Dam, Canada), there were two projects in the execution phase (Petra Nova and Kemper County, USA).
The USA is a good example of the positive effects of policy incentives on EOR projects. In the 1980s, a decrease in US domestic oil production led to the passing of the Windfall Profit Tax, which triggered the application of EOR by a significant reduction of its tax burden. Today, the US 45Q tax credit has been amended to provide a tax reduction of 35$/t of stored CO 2 by EOR activities. The International Energy Agency (IEA) New Policies Scenario predicts a greater number of oil fields to become mature and therefore inclined to new EOR developments. According to the same scenario, the total EOR production will grow up to more than 4.5 × 10 6 bbl/d, accounting for approximately 4% of global oil production in 2040 [52].  The application of CCS technologies to a new conventional power plant can reduce CO 2 emissions by up to 90%. However, the high costs of capturing and compressing CO 2 is reflected in an energy price increase of 21-91%, especially in the case of distant transportation [42,55]. Although CCS was initially considered to be an acceptable solution for coal-based power facilities, low natural gas prices and renewable energy development are replacing coal-based power production in developed regions, which resulted in fewer CCUS application cases.
The CO 2 -EOR case studies shown in Table 2 (in total 23) are briefly described below. Val Verde Natural Gas Plants, TX, USA. Before the construction of the Pensoi pipeline in the mid-1970s, four natural gas processing plants in the Val Verde area was venting over 2 Mt/y of CO 2 . However, in 1996, this pipeline was converted into a natural gas transportation pipeline, again causing venting of significant quantities of CO 2 . Therefore, it was decided to redirect emitted CO 2 by a new pipeline to the EOR projects in West Texas, located at a distance of several hundred kilometers. Nowadays, five separate gas-processing facilities in the Val Verde area are capturing around 1.3 Mt/y of CO 2 for use in EOR operations at the Sharon Ridge oilfield. The CO 2 content of the inlet gas stream at the Val Verde plant is in the range of 25 to 50% [56]. The application of CCS technologies to a new conventional power plant can reduce CO2 emissions by up to 90%. However, the high costs of capturing and compressing CO2 is reflected in an energy price increase of 21-91%, especially in the case of distant transportation [42,55]. Although CCS was initially considered to be an acceptable solution for coal-based power facilities, low natural gas prices and renewable energy development are replacing coal-based power production in developed regions, which resulted in fewer CCUS application cases.
The CO2 -EOR case studies shown in Table 2 (in total 23) are briefly described below. Val Verde Natural Gas Plants, TX, USA. Before the construction of the Pensoi pipeline in the mid-1970s, four natural gas processing plants in the Val Verde area was venting over 2 Mt/y of CO2. However, in 1996, this pipeline was converted into a natural gas transportation pipeline, again causing venting of significant quantities of CO2. Therefore, it was Enid Fertilizer CO 2 -EOR Project, OK, USA. This is one of the largest fertilizer production plants in North America, producing ammonia, liquid fertilizer and urea. The original plant was built in 1974, which was further upgraded in the 2000 s. Since 1982, about 0.7 Mt/y of CO 2 has been transported by a 225 km long pipeline and injected into depleted oil fields in southern Oklahoma for the purpose of EOR [56].
Shute Creek Gas Processing facility Wyoming, USA. It has been processing natural gas from the LaBarge field since 1986. The raw gas is of the lowest hydrocarbon content commercially produced in the world (about 20%), containing CO 2 in high concentration (65%). In order to separate sour gases, the Shute Creek Gas Processing facility was built. Before upgrading, H 2 S along with approximately 0.4 Mt/y of CO 2 were disposed of. An expansion in plant capacity was completed in 2010, reaching a capturing capacity of 7 Mt/y of CO 2 . The separated CO 2 is transported from the Shute Creek facility via the ExxonMobil, Chevron and Anadarko Petroleum pipeline systems to oil fields in Wyoming and Colorado for use in EOR activities. The pipeline distance from Shute Creek to the larger volume customers of Salt Creek and Rangely is approximately 460 km and 285 km, respectively [56].
Great Plains Synfuel Plant and Weyburn-Midale Project, Saskatchewan, Canada. The Great Plains Synfuel Plant, North Dakota, began with operation in 1984, representing the only commercial-scale coal gasification plant in the USA that produces synthetic natural gas. Since the waste stream contains a high content of CO 2 (95%), no further processing is required. The CO 2 is transported by a 329 km pipeline to the Weyburn and Midale oil fields Saskatchewan, Canada. About 2.4 Mt/y of CO 2 is injected into the Weyburn field, and approximately 0.6 Mt/y of CO 2 is injected into the Midale field. The main injection target zones are at a depth of about 1500 m. The Weyburn-Midale CO 2 Monitoring and Storage Project was conducted in the period 2000-2011, supported by the International Energy Agency (IEA) Greenhouse Gas Research and Development Program, with a focus on monitoring behavior of the injected CO 2 and permanent storage [56].
Century Plant, TX, USA. It is used for processing high CO 2 -content (more than 60%) gas streams produced from different reservoirs in West Texas. It began operating in 2010 with a smaller level of capturing capacity, but in 2012, the capacity extended to its full level of 8.4 Mt/y. After being compressed, the CO 2 is transported to an industrial hub located in Denver City by a 160 km long pipeline and is finally injected into the Permian Basin for EOR activities. The Permian Basin of West Texas and southeast New Mexico is one of the largest and most active oil basins in the USA [56].
Air Products Steam Methane Reformer EOR Project, TX, USA. It has been operating since 2012. It captures approximately 1 Mt/y of CO 2 at two steam methane reformers at the Port Arthur energy refinery. Captured CO 2 is transported by 158 km of pipelines to an oil field for EOR. After 21 km, the pipeline is connected to a much larger diameter Green Pipeline, used for the collection and transportation of CO 2 from different sources [56][57][58].
The Petrobras Santos Basin CO 2 -EOR project, Brazil. It is located offshore, approximately 300 km from the coast. EOR is applied to the Petrobras Lula oilfield, which is one of the largest oil fields in Brazil, positioned in the pre-salt carbonate reservoir, just below a thick, 2000 m salt column. After pilot injection of produced reservoir gas into the oil field, large-scale production began in 2013. Membrane processing units installed on-board of the floating production facility are used for the separation of the CO 2 from the produced natural gas. While natural gas is transported to an onshore facility by pipeline, the CO 2 is compressed and reinjected into the hydrocarbon's producing reservoir. The produced oil is transported to shore by tankers. The project is known for the deepest CO 2 injection well in operation. Since 2017, CO 2 reinjection has been carried out by ten floating production storage and offloading (FPSO) units: seven at Lula Field, two at Sapinhoá Field and one at Lapa Field [59][60][61].
Coffeyville Gasification Plant, KS, USA. The project is an example of CCS applied to the fertilizer industry, which has been operational since 2013. The process of nitrogen fertilizer production involves petroleum coke gasification and synthetic natural gas creation. Although CO 2 generated in the process is used for fertilizer manufacturing, a significant part of the CO 2 is vented. Up to 1 Mt/y of the CO 2 is captured by a carbon capture unit and is then delivered to the North Burbank Oil Unit in Oklahoma for EOR purposes [56].
The Lost Cabin Gas Plant CCS project, WY, USA. The project operates with a precombustion capture of 0.9 Mt/y of CO 2 . The feed gas, which has been purified at the Lost Cabin Gas Plant since 1996, contains around 20% of CO 2 . In 2013, the plant was connected with the EOR injection site at the Bell Creek oil field in MT, USA, by the 374 km long Greencore pipeline [56].
Boundary Dam 3, Saskatchewan, Canada. This project represents the world's very first full-chain CCS applied on a coal-fired power plant. While producing 110 MW of electricity, it simultaneously enhances oil recovery and significantly reduces CO 2 emissions by capturing and injecting up to 1 Mt/year of CO 2 into 1.4 km deep Weyburn oilfield reservoirs and into a 3.4 km deep saline reservoir (Deadwood formation). Captured SO 2 is used as feedstock for a sulfuric acid plant [58].

Uthmaniyah Carbon Dioxide Enhanced Oil Recovery (CO 2 -EOR) Demonstration
Project, Saudi Arabia. The project captures approximately 0.8 Mt/y of CO 2 . The captured CO 2 is compressed and transported via an 85 km pipeline to the injection site in Uthmaniyah field, which is a part of the giant Ghawar field (the largest oil field in the world). Besides the determination of additional oil recovery and sequestered CO 2 quantities, the project goals are related to risk analyses and the identification of operational concerns. A comprehensive monitoring and surveillance plan, including advanced routine logging and use of new technologies for plume tracking and CO 2 saturation modeling, follow the CO 2 -EOR operations [60].
Kemper County Energy Facility, MI, USA. It was a lignite based integrated gasification combined-cycle (IGCC) facility designed to convert locally mined lignite to synthesis gas. It was planned to be the first commercial application of air-blown transport integrated gasification (TRIG) technology. The peak capacity of 582 MW would occur when using both syngases in the combustion turbine and natural gas firing in the heat recovery steam generator duct burners. After carbon capture and removal of impurities, purified syngas would be used as fuel for combined-cycle power generating units. The project was expected to capture approximately 3 Mt/y of CO 2 . One part of it would be sent by a 98 km CO 2 pipeline and used for EOR at Heidelberg oil field, replacing temporary EOR solution, which uses CO 2 from natural CO 2 reservoir. The rest of captured CO 2 would be sent by an 87 km pipeline to another oil field in the vicinity of West King, Mississippi. The startup was originally projected for 2014, but due to a number of technical issues and huge costs, it was decided to operate using natural gas, without carbon capture and storage technology [56,62].
Petra Nova Carbon Capture facility, Huston, TX, USA. It was installed at the W. A. Parish power coal plant, and started with operations in 2017, as the world's largest postcombustion CO 2 capturing system, intended to capture 1.4 Mt/y of CO 2 . Captured CO 2 was planned to be transported via a 130 km pipeline and injected into the West Ranch oil field. Nevertheless, very shortly after a successful start, a drop in oil prices in the first half of 2020 caused CO 2 capture at Petra Nova to become uneconomical. Further project operation may be under the federal 45Q tax credit incentive, ensuring companies $35 per metric ton (1.102311 t) of geologically stored CO 2 within the EOR and up to $50 for its storage in a saline formation [63,64].
Abu Dhabi CCS, Mussafah, United Arab Emirates. It is the first fully commercial large-scale CCS facility applied in the iron and steel industry, the Emirates Steel Industries factory. About 0.8 Mt/y of CO 2 , which is produced as a byproduct of the direct reduced ironmaking process, is captured and transported via pipeline to oil reservoirs for EOR purposes. Abu Dhabi National Oil Company is developing its second CCUS facility in the United Arab Emirates, which would capture 1.9 to 2.3 Mt/y of CO 2 from its gas processing plant that will be used for EOR purposes in the same reservoir [56,60].
The Alberta Carbon Trunk Line (ACTL) CCUS, Alberta, Canada. The system started with full operation in 2020. It captures about 1.3 Mt/y of CO 2 from a bitumen refinery using gasification technology (North West Redwater Partnership Sturgeon Refinery), while an additional 0.3-0.6 Mt/y of CO 2 is gained from the Agrium's Redwater fertilizer plant. Captured CO 2 serves for the production of 1 billion bbl of oil from the Clive oil reservoir. The ACTL (16" trunkline), constructed in the length of 240 km with a huge capacity of 14.6 Mt/y of CO 2, is the largest capacity pipeline for the transportation of anthropogenic CO 2 . It will enable the connection of different emission sources, including coal-fired power plants, upgrading/refining operations, petrochemicals, and a natural gas processing plant [56,60].
Under defining and evaluation phases, there are eight large-scale CO 2 -EOR projects. Most of them (63%) are planned in China despite the fact that tight continental geology and heavier oil pose significant issues [65]. With regard to the CO 2 source industry, there are an equal share of power generation and chemical production facilities (40%). While emerging Asian economies are still leaning on coal-based energy, and carbon capture and storage is seen as an effective emission reduction solution, a comprehensive framework and policy support are still missing [14,65].
Sinopec Shengli Power Plant, Dongying, Shangdong province, China. The project considers a conventional amine-based CO 2 capture facility installed at the 25 MW Unit 1 of the coal-fired power plant. The implemented post-combustion capture process enables CO 2 delivery to the Shengli oil field for EOR purposes. In the project's final stage, about 1 Mt/y of CO 2 will be captured, transported, and injected to increase oil recovery by up to 15%. Shengli oil field is the second-largest oil field in China, producing around 200 million bbl/y of oil. More favorable economic conditions, i.e., higher oil prices, are required for startups [53].
Sinopec Qilu Petrochemical Project, Shangdong Province, China. The project considers CCS applied at the Shengli coal-fired power plant. It captures up to 0.5 Mt/y of CO 2, which is transported via gas pipeline to Shengli oil field for EOR [66].
Yanchang Integrated CCS Demonstration Facility, China. It is designed to capture CO 2 from a coal gasification unit. The 0.05 Mt/y of CO 2 unit has been in operation since 2012, while the larger 0.36 Mt/y of CO 2 capture is under construction. Captured CO 2 would be used for EOR in oil fields in the Ordos Basin. Since they are facing a severe water shortage, CO 2 -EOR would be a great solution for Yanchang Oilfield [67,68].
PetroChina Jilin Oil Field EOR Project (Phase 2), Jilin Province, China. CO 2 -EOR operations have been performed on the Jilin oil field since 2006. The CO 2 source is a natural gas processing facility that processes natural gas from the Changchun gas field that contains approximately 2.5% CO 2 . Phase 2 refers to the extension to a larger scale CO 2 -EOR, which would sequester 0.8-1 Mt/y of CO 2 and increase oil production by 500,000 t/y [11].
Texas Clean Energy Project, TX, USA. It was a proposed 400 MW coal-fired power plant with installed capturing technology of 2.4 Mt/y. The project would combine Integrated gasification combined cycle (IGCC) technologies, carbon monoxide (CO) shift, and Linde Rectisol ® wash unit (RWU) acid gas removal (AGR). A part of the captured CO 2 would be used for EOR activities in the West Texas Permian Basin, while another part of the captured CO 2 , as well as a portion of the high-H 2 syngas, would be used for urea fertilizer production. Captured sulfur-containing gases would be converted to marketable sulfuric acid [69]. Although an environmental impact statement was issued in 2011, an operation was planned by 2018; the bankruptcy of the company's sponsor, Summit Power, occurred in 2017 after the US Department of Energy (DOE) decided to give up financial support due to improper spending of money.
Riley Ridge Sweetening Plant, WY, USA. A pre-combustion CO 2 capture plant was designed to capture 2.5 Mt/y of CO 2 . Sour gas, produced from the Madison Formation, which contains CO 2 , N 2 , CH 4 , He, and H 2 S, is originally processed at the Riley Ridge Treatment plant, which has been in operation since 2013. Separated CH 4 and He are sold, while non-gaseous H 2 S/CO 2 mixture is planned to be transported via 16" pipeline to the Riley Ridge Sweetening Plant. After separation, H 2 S would be reinjected into deep injection wells, while the CO 2 would be transported via a 24" CO 2 pipeline (the Greencore Pipeline), planned to connect another source of CO 2 , which would be provided from the existing Shute Creek Gas Plant. The CO 2 destination is Bell Creek Field and other oilfields in SE Montana, where it will be used for EOR purposes. Produced CO 2 , separated from the oil at the surface, would be reinjected into the oil recovery process, which means that after field decommissions, it would remain permanently geologically stored [70].
Huaneng GreenGen IGCC project, Tianjin, China. The project has been developing through three phases. The first two project phases refer to the construction of a 250 MW integrated gasification combined cycle (IGCC) facility (completed in 2012) and the construction of a pilot facility that produces electricity from hydrogen with a small size capturing of 0.2 Mt/y of CO 2 . The third phase refers to the construction of a 400 MW IGCC power plant with an installed unit of 2 Mt/y of CO 2 capture capacity. The captured CO 2 fate is still unknown, but one of the solutions considers EOR application at the Tianjin Dagang oil field [65].

CO 2 -EOR Site Emissions
Besides the fact that CO 2 is the most abundant greenhouse gas, causing increased global warming and consequently climate changes, which result in a wide spectrum of consequences, CO 2 is also directly adverse to human health and nature in high concentrations. Humans are immediately endangered if CO 2 concentration in the air rises above 7-10%, while plants, insects and soil organisms show a higher tolerance [10]. Furthermore, a higher concentration of CO 2 in a marine environment leads to seawater pH reduction, while partial pressure enhancement is responsible for physical stress [71]. Due to the previously mentioned facts, it is of high importance to manage CO 2 in a closed system to prevent any leakage to the atmosphere during all phases of the CCS process. In order to achieve that, for leakage risk mitigation, special technical and non-technical measures during the processes of CO 2 capture, transportation and injection into geological formations must be applied.
Although in the CO 2 -EOR production process, CO 2 is the predominant hazardous compound, other harmful substances may also appear. Besides hazardous byproducts characteristic for hydrocarbon production (e.g., produced water contains traces of light hydrocarbons: BTEX, naphthalene, PAHs, alkylphenols, etc.), other CO 2 related hazards (e.g., capture chemicals, or formation of strong acids from traces NO x and SO x gases) are possible. Trace elements (As, Cd, Hg, Pb, etc.) can appear as products from CO 2water-reservoir interactions, or some radioactive elements (e.g., Ra), which are prone to be incorporated in scaling minerals, can appear [71].
Different emission sources that could occur across CCS and/or CO 2 -EOR project activities are shown in Figure 7.  CO2-EOR project emissions (combustion, vented and fugitive emission) can be observed as direct and indirect emissions. Engines, heaters, and flares (combustion emissions), venting points (intentional gas release from non-combustion sources) and joints (fugitive emissions) on processing vessels, tanks, pipelines, and other equipment refer to the direct CO2 emissions sources. Indirect emissions from the petroleum industry come from different powering equipment and devices producing power outside the petroleum industry (e.g., CO2, CO, N2O, CH4 are emitted at power plants during electricity generation), and therefore are also present in all phases of the EOR process (CO2 stream compression, water-alternating-gas (WAG) injection, reservoir fluid production, fluid processing, etc.). The intensity of indirect emissions is proportional to energy consumption and depends on the energy source. However, in the case of on-site power production CO 2 -EOR project emissions (combustion, vented and fugitive emission) can be observed as direct and indirect emissions. Engines, heaters, and flares (combustion emissions), venting points (intentional gas release from non-combustion sources) and joints (fugitive emissions) on processing vessels, tanks, pipelines, and other equipment refer to the direct CO 2 emissions sources. Indirect emissions from the petroleum industry come from different powering equipment and devices producing power outside the petroleum indus-try (e.g., CO 2 , CO, N 2 O, CH 4 are emitted at power plants during electricity generation), and therefore are also present in all phases of the EOR process (CO 2 stream compression, water-alternating-gas (WAG) injection, reservoir fluid production, fluid processing, etc.). The intensity of indirect emissions is proportional to energy consumption and depends on the energy source. However, in the case of on-site power production (usually in the case of offshore production or on-site power production from an associated gas produced during oil production), emissions related to energy production are considered as a part of direct emissions. Fugitive emissions refer to unintentional gas releases (CH 4 , volatile organic compounds (VOCs), CO 2 , N 2 O) from pressurized equipment at a connection point (e.g., valves, flanges, pipe connections, mechanical seals, etc.) due to imperfect hermetical tightness. Even though compared to the combustion and vented emissions, fugitive emissions are relatively small (up to 5% of total emissions in upstream activities [72]), sealing device degradation, equipment failures and operating conditions (pressure, temperature, etc.) may lead to its increase. A simplified overview of the emissions occurring during the EOR process is given in Table 3 and Figure 8.  Dilmore [73] assessed atmospheric emissions occurring during site evaluation and characterization, construction, closure, and post-closure monitoring to be less than 1% of total emissions resulting from CO2-EOR activity, which means that the remaining 99% is assigned to project operation.
Dilmore [73] assessed atmospheric emissions occurring during site evaluation and characterization, construction, closure, and post-closure monitoring to be less than 1% of total emissions resulting from CO 2 -EOR activity, which means that the remaining 99% is assigned to project operation. CO 2 capture processes (Figure 8) are, compared to other CCS/CO 2 -EOR phases, most energy-intensive (use of fossil fuels or electricity) and therefore most emission-intensive. In that phase of the CO 2 -EOR project, all types of petroleum industry emissions occur (combustion, vented and fugitive emissions). Captured gas processing activities (impurity extraction, dehydration, compression, etc.) are also sources of combustion, vented and fugitive emissions.
In this phase, different types and different concentrations of impurities may appear in the CO 2 stream, depending on the CO 2 emission source (gas or coal-based power plant, cement plant, natural gas processing plant, ammonia plant, etc.), and on the type of capture process. If the captured gas is not processed at the capture site (CO 2 source site), the CO 2 capturing process results in reduced emissions at the CO 2 source site, but in that case, the environmental impact of the CO 2 -EOR project on the atmosphere is moved to the injection/storage site. While a post-combustion scrubbing process results in a low level of impurities, the pre-combustion process results in a CO 2 stream with 1-2% impurities in the form of H 2 , CO, traces of H 2 S, and other sulfur compounds. An oxyfuel process CO 2 stream contains O 2 , N 2 , Ar, SO x and NO x , which requires an impurity reduction in the subsequential cryogenic purification process [42]. CO2 capturing process results in reduced emissions at the CO2 source site, but in that case, the environmental impact of the CO2-EOR project on the atmosphere is moved to the injection/storage site. While a post-combustion scrubbing process results in a low level of impurities, the pre-combustion process results in a CO2 stream with 1-2% impurities in the form of H2, CO, traces of H2S, and other sulfur compounds. An oxyfuel process CO2 stream contains O2, N2, Ar, SOx and NOx, which requires an impurity reduction in the subsequential cryogenic purification process [42].  [39,53].
Even though there are some other transport options (ship or truck transport), CO2 is usually transported by pipelines. Dominant emissions during the transport of pressurized CO2 are fugitive emissions. Fugitive emissions from CO2 pipeline transport depend on the CO2 stream composition as well as the type, number and size of the equipment installed in the pipeline systems. Compressors, as the most important part of a CO2 transmission system, are the main sources of combustion emissions during CO2 transport. To ensure the supercritical state of CO2, the high injection pressure is needed, which makes CO2 compression/pumping to be highly energy-intensive, and therefore the most emissionintensive process. If the compressors are powered by an electric drive, the compression process only results in indirect CO2 emission (generated at a power plant). Direct CO2 emissions may occur in the case of gas-engine-driven compressors. However, emission quantities are determined by the pressure of delivered CO2 and the required injection pressure (depends on the reservoir pressure). Pipelines or tanks (in case of transport by ships, trucks, or intermediate storage) are also potential sources of vented emissions (maintenance, emergency releases, etc.).
Emissions associated with CO2 injection activities include all types of emissions (combustion, vented and fugitive) from surface equipment as the emission sources. A common surface CO2-EOR operation site is comprised of an injection system (distribution manifold Figure 8. CO 2 capture processes. Modified according to [39,53]. Even though there are some other transport options (ship or truck transport), CO 2 is usually transported by pipelines. Dominant emissions during the transport of pressurized CO 2 are fugitive emissions. Fugitive emissions from CO 2 pipeline transport depend on the CO 2 stream composition as well as the type, number and size of the equipment installed in the pipeline systems. Compressors, as the most important part of a CO 2 transmission system, are the main sources of combustion emissions during CO 2 transport. To ensure the supercritical state of CO 2 , the high injection pressure is needed, which makes CO 2 compression/pumping to be highly energy-intensive, and therefore the most emissionintensive process. If the compressors are powered by an electric drive, the compression process only results in indirect CO 2 emission (generated at a power plant). Direct CO 2 emissions may occur in the case of gas-engine-driven compressors. However, emission quantities are determined by the pressure of delivered CO 2 and the required injection pressure (depends on the reservoir pressure). Pipelines or tanks (in case of transport by ships, trucks, or intermediate storage) are also potential sources of vented emissions (maintenance, emergency releases, etc.).
Emissions associated with CO 2 injection activities include all types of emissions (combustion, vented and fugitive) from surface equipment as the emission sources. A common surface CO 2 -EOR operation site is comprised of an injection system (distribution manifold at the end of the transport pipeline, distribution pipelines to wells, additional compression facilities, measurement and control systems, and the injection wells), produced fluid (gas and liquid) separation and processing units, brine management units, CO 2 recompression or recycle gas unit and optionally artificial lift equipment (Figure 9).
Direct emissions at the injection site are related to CO 2 and CH 4 and, to a lesser extent, to nonmethane volatile organic compounds (NMVOCs), N 2 O, CO, SO 2 and NO x releases. VOC are released due to pressure and/or temperature changes in the tank (surface storage of the produced oil prior to transport to the refinery) caused by surface conditions and loading and unloading activities. Released from oil into the space between the tank content level and the tank roof, volatiles are usually vented directly from the tank into the atmosphere [72].
When a reservoir's natural drive is not sufficient for bringing the fluid up to the surface, a method of artificial lift must be applied to increase the oil production rate. Artificial lift methods (selection primarily depending on the well depth, hydrocarbon composition and production rate) vary in energy consumption; thus, the indirect emissions vary through this phase of the project. The lowest energy consuming method, if any, is applied when a low viscosity fluid, e.g., oil with dissolved CO 2 , is produced [74]. loading and unloading activities. Released from oil into the space between the tank content level and the tank roof, volatiles are usually vented directly from the tank into the atmosphere [72]. When a reservoir's natural drive is not sufficient for bringing the fluid up to the surface, a method of artificial lift must be applied to increase the oil production rate. Artificial lift methods (selection primarily depending on the well depth, hydrocarbon composition and production rate) vary in energy consumption; thus, the indirect emissions vary through this phase of the project. The lowest energy consuming method, if any, is applied when a low viscosity fluid, e.g., oil with dissolved CO2, is produced [74]. During CO2-EOR, a certain amount of the injected CO2 is produced along with oil. The injected CO2, produced along with associated gas, is recaptured and reinjected into the geological formation. The gathering of EOR produced oil is carried out by pipelines. At this stage, potential emissions are related to fugitive emissions from the equipment, gas-operated pneumatic devices and valves.
The first step in the produced hydrocarbon processing is the separation of the produced fluids (oil, gas (in the case of CO2-EOR natural gas and CO2) and water). A bulk separator is a three-phase vessel. Oil and gas separation commonly results in vented CH4 emissions (separators and tanks), as well as CH4 fugitive emission. In the case of CO2-EOR, since CO2 is a part of the gaseous phase of the production fluid, the vented and fugitive emissions, except CH4, also contain a significant portion of CO2. If the heat from fossil fuel combustion is used during the separation process, additional emissions of CO2 and N2O are present [72]. Natural gas processing is done in order to comply with the gas quality specifications. It can be achieved by chemical adsorption (an amine process), by cryogenic fractionation, or by adsorption using molecular sieves [65]. If the associated gas is produced at a high enough pressure, and if there is adequate infrastructure for its gathering and processing, it can be used on-site as a powering fuel. In some cases, the high During CO 2 -EOR, a certain amount of the injected CO 2 is produced along with oil. The injected CO 2 , produced along with associated gas, is recaptured and reinjected into the geological formation. The gathering of EOR produced oil is carried out by pipelines. At this stage, potential emissions are related to fugitive emissions from the equipment, gas-operated pneumatic devices and valves.
The first step in the produced hydrocarbon processing is the separation of the produced fluids (oil, gas (in the case of CO 2 -EOR natural gas and CO 2 ) and water). A bulk separator is a three-phase vessel. Oil and gas separation commonly results in vented CH 4 emissions (separators and tanks), as well as CH 4 fugitive emission. In the case of CO 2 -EOR, since CO 2 is a part of the gaseous phase of the production fluid, the vented and fugitive emissions, except CH 4, also contain a significant portion of CO 2 . If the heat from fossil fuel combustion is used during the separation process, additional emissions of CO 2 and N 2 O are present [72]. Natural gas processing is done in order to comply with the gas quality specifications. It can be achieved by chemical adsorption (an amine process), by cryogenic fractionation, or by adsorption using molecular sieves [65]. If the associated gas is produced at a high enough pressure, and if there is adequate infrastructure for its gathering and processing, it can be used on-site as a powering fuel. In some cases, the high cost of CO 2 separation from the produced associated gas justifies reinjection of the entire reproduced gas stream [76][77][78]. Nowadays, with high environmental standards and the knowledge of the significant global warming potential (GWP) of CH 4 , the release of the associated gas into the atmosphere is not considered to be a viable solution, so flaring and venting are considered solely as safety actions, used for emergency shutdown, injectivity issues or maintenance activities.
As mentioned before, fugitive emissions are related to all process units operating at the CO 2 -EOR injection site. Although they are still not well investigated, it is assumed that the amount up to a 2% loss of purchased CO 2 [73]. CO 2 can escape from a geological formation if its pressure, when injected into the formation, exceeds formation capillary and fracture pressure, resulting in its passing through the caprock. Other leakage risks refer to CO 2 escape through poorly plugged abandoned wells, faults, or fractures. The low leakage probability of a geological storage site is assured by the selection of the injection formation that meets all the needed prerequisites, such as impermeable cap and bedrocks, geological stability, the absence of leakage paths and effective trapping mechanisms [79,80].

CO 2 -EOR Lifecycle Emissions
It is well-known that during EOR processes, a certain amount of CO 2 is permanently retained and stored in the injection formation, but up to which level can a real emission reduction during the CO 2 -EOR process be achieved? First, to achieve emission reductions, CO 2 anthropogenic sources are required. When CO 2 comes from its natural underground reservoirs, a net negative emission is impossible to achieve. Even though in CO 2 -EOR projects, CO 2 is injected with the function of a solvent and a portion of it is produced with a mixture of brine and hydrocarbons, ultimately about 60% of the injected CO 2 remains trapped in the oil reservoir pore space, while around 40% of it is reproduced with the reservoir fluids (hydrocarbons and brine). However, as per Melzer [81], up to 95% of the EOR injected CO 2 can be permanently retained within the reservoir if the closed-loop injection system is applied, which implies produced fluid separation and reinjection of the reproduced CO 2 .
According to International Energy Agency (IEA), EOR activities in the USA use 0.3-0.6 t CO 2 /bbl of produced oil [82]. However, the primary goal of the EOR project is additional oil production that generates additional emissions, but besides the already mentioned emissions resulting from production processes, there is a whole range of production-related activities that generate emissions, as well as the emissions generated by the final product usage (fossil fuel burning). Therefore, the environmental performance of CO 2 -EOR projects must be assessed, which is possible by the lifecycle assessment technique.
Lifecycle analyses for the CO 2 -EOR technological systems appear in different literature [83][84][85][86][87][88][89], where the benefit of stored CO 2 is put against the environmental impact of the required additional process. All the studies concur on the substantial benefits of CO 2 emission reduction.
Azzolina et al. [90] made a lifecycle analysis of incremental oil produced by CO 2 -EOR by developing an integrated model with a coal-based power plant and quantitative analysis of GHG emissions in comprehensive system boundaries. The system boundaries were the same as those used by Cooney et al. [91].
Cooney et al. differed emissions by upstream (coal mining, processing and transport; coal-burning with CO 2 capture, and CO 2 transport), "gate-to-gate" (emissions associated with site operation), and downstream (crude oil transport, refining, fuel transport, fuel combustion). As a result of the analysis, the incremental oil was lower-carbon fuel that resulted in a lower emission factor. Coal mining, processing and transport have an average emission factor of 60.7 kg CO 2 eq/MWh. The emission factor of a coal-based power plant with 85% CO 2 capture is about 146 kg CO 2 eq/MWh, while the emission factor for CO 2 pipeline transport from the capture unit to the CO 2 injection site amounts to 9.93 × 10 4 kg emitted/kg of CO 2 transport. Downstream emissions are at the level of 485 kg CO 2 eq/bbl [91].
As per the Clean Air Task Force (CATF) [92] (Figure 10), lifecycle emissions for conventional oil production (well-to-wheel boundaries) are 0.51 t CO 2 /bbl. Average use of 0.3 t CO 2 /bbl in EOR would decrease conventional lifecycle emissions to 0.21 t CO 2 /bbl. However, given that EOR site operations increase process emissions by 0.03 t CO 2 /bbl, that the additional emissions from incremental oil consumption amount to 0.04 t CO 2 /bbl, and the emissions from conventional oil production not displaced by EOR also amount to 0.04 t CO 2 /bbl, it can be concluded that every CO 2 -EOR produced barrel emits 0.32 t of CO 2 . Compared to conventional oil production, CO 2 emissions are decreased by about 37% [92]. additional emissions from incremental oil consumption amount to 0.04 t CO2/bbl, and the emissions from conventional oil production not displaced by EOR also amount to 0.04 t CO2/bbl, it can be concluded that every CO2-EOR produced barrel emits 0.32 t of CO2. Compared to conventional oil production, CO2 emissions are decreased by about 37% [92]. Thorne et al. [93] developed a conceptual EOR system with an oxyfuel power plant in Poland, as the CO2 source, and an oil reservoir on the Norwegian continental shelf, as the EOR operational site. The model used ship transport of CO2 based on two ships transporting CO2 over a distance of 1253.3 km (677 nautical miles) and resulted in 71% emission reduction compared to a non-CCUS system (a case when oil and electricity are conventionally produced).
Shminchak et al. [94] documented a GHG lifecycle analysis of the CO2-EOR site in the Northern Michigan Basin, USA. In the period 1996-2017, about 2.29 × 10 6 bbl of oil was produced by cycling a total of 2.09 × 10 6 t of CO2 into 1500-2000 m deep reservoirs. The lifecycle analysis, based on site-specific operational records, included the processes shown in Figure 11. All of them had total emissions of 1.93 × 10 6 t of CO2 eq. Thus, the lifecycle analysis showed negative net emissions of −0.16 × 10 6 t of CO2 eq. However, CO2 process emissions highly depend on the equipment used., e.g., a CO2 capture process applied at a natural gas processing facility has lower emissions than CO2 captured from coal-fired power plants, the CO2 compressors which use natural gas have fewer emissions than electrical compressors which use electricity generated by coal-fired power plants, and the oil-CO2 separation method which includes high-and low-pressure separators, is less energyintensive than other gas separation methods. Figure 11. Cradle-to-grave CO2-EOR emission processes. Modified according to [94]. Thorne et al. [93] developed a conceptual EOR system with an oxyfuel power plant in Poland, as the CO 2 source, and an oil reservoir on the Norwegian continental shelf, as the EOR operational site. The model used ship transport of CO 2 based on two ships transporting CO 2 over a distance of 1253.3 km (677 nautical miles) and resulted in 71% emission reduction compared to a non-CCUS system (a case when oil and electricity are conventionally produced).

Discussion
Shminchak et al. [94] documented a GHG lifecycle analysis of the CO 2 -EOR site in the Northern Michigan Basin, USA. In the period 1996-2017, about 2.29 × 10 6 bbl of oil was produced by cycling a total of 2.09 × 10 6 t of CO 2 into 1500-2000 m deep reservoirs. The lifecycle analysis, based on site-specific operational records, included the processes shown in Figure 11. All of them had total emissions of 1.93 × 10 6 t of CO 2 eq. Thus, the lifecycle analysis showed negative net emissions of −0.16 × 10 6 t of CO 2 eq. However, CO 2 process emissions highly depend on the equipment used., e.g., a CO 2 capture process applied at a natural gas processing facility has lower emissions than CO 2 captured from coal-fired power plants, the CO 2 compressors which use natural gas have fewer emissions than electrical compressors which use electricity generated by coal-fired power plants, and the oil-CO 2 separation method which includes high-and low-pressure separators, is less energy-intensive than other gas separation methods.
in Figure 11. All of them had total emissions of 1.93 × 10 t of CO2 eq. Thus, the lifecycle analysis showed negative net emissions of −0.16 × 10 6 t of CO2 eq. However, CO2 process emissions highly depend on the equipment used., e.g., a CO2 capture process applied at a natural gas processing facility has lower emissions than CO2 captured from coal-fired power plants, the CO2 compressors which use natural gas have fewer emissions than electrical compressors which use electricity generated by coal-fired power plants, and the oil-CO2 separation method which includes high-and low-pressure separators, is less energyintensive than other gas separation methods. Figure 11. Cradle-to-grave CO2-EOR emission processes. Modified according to [94].

Discussion
Climate issues related to increasing concentrations of CO2, mainly released during fossil fuel combustion during power production, put strong initiatives to limit the use of fossil fuels and to increase the employment of alternative power production solutions like renewable energy sources. On the other hand, due to variability in the availability of renewable energy sources, the cost of energy production from it, along with energy storage issues and the constantly increasing global energy demand, especially in developing countries, the world still strongly depends on fossil fuels, and the transition to a carbon- Figure 11. Cradle-to-grave CO 2 -EOR emission processes. Modified according to [94].

Discussion
Climate issues related to increasing concentrations of CO 2 , mainly released during fossil fuel combustion during power production, put strong initiatives to limit the use of fossil fuels and to increase the employment of alternative power production solutions like renewable energy sources. On the other hand, due to variability in the availability of renewable energy sources, the cost of energy production from it, along with energy storage issues and the constantly increasing global energy demand, especially in developing countries, the world still strongly depends on fossil fuels, and the transition to a carbonfree society will take place over several decades. A possible solution for the transition is seen in CCS and CCUS technologies, which allow the use of fossil fuels while eliminating the adverse climate change impacts associated with greenhouse gas emissions. Both technologies eliminate a facility's direct CO 2 emissions. Although the primary goal of CCS and CCUS technologies is CO 2 sequestration, both technologies result in a certain amount of emissions. Even though CCUS, along with CO 2 sequestration, creates additional benefits (production of new products), sometimes, depending on the type of project, it is a less favorable solution compared to CCS (in cases when CO 2 retention time is relatively short).
CCS comprises various technical and technological solutions depending on the size and type of CO 2 source, capture technology, transportation mean, and the final storage destination (distance from the CO 2 source, depth and characteristics of the geological formation, etc.). Currently, the only type of large-scale CCUS projects are CO 2 -EOR projects (see Table 2, Figures 5 and 6), which, along with CO 2 sequestration, also result in residual oil production. According to the KAPSARC database [42], in 2018, 11 of 23 large-scale CO 2 -EOR projects were in operation (48%) (see Table 2), grouped, by related industries where applied, into natural gas processing (6 projects, or 55%), fertilizer production (2 projects, or 18%), power generation (1 project, or 9%), synthetic natural gas (1 project, or 9%), and hydrogen production (1 project, or 9%). The rest of the projects were in the execution stage (5 projects, or 22%), definition stage (5 projects, or 22%) or evaluation stage (2 projects, or 9%). With regard to the large-scale CO 2 -EOR projects in the execution phases, there is a visible shift towards smaller capacity projects and other industry applications, such as iron and steel production, fertilizer production and oil refining ( Figure 6).
Regarding the capture capacity of these projects, projects related to natural gas processing (52%) have the largest share of capture capacity. This is expected since, as mentioned before, most of the large-scale CO 2 -EOR projects are related to natural gas processing, which is not surprising since CO 2 injection technology was developed by the petroleum industry. The capture capacity of large-scale CO 2 -EOR projects related to power production is 26%, fertilizer production 5%, synthetic natural gas 7%, oil refining 3%, iron and steel production 2% and hydrogen production 2%.
As can be seen, all of the mentioned projects differ by CO 2 source type and size (and if the same, they differ by fuel type, net output, efficiency, capture technology, capture capacity, captured CO 2 purity, etc.), CO 2 transport (choice of the transportation system and used fuel, distance from the CO 2 capture point to injection/storage point, etc.), injection/storage site characteristics, time horizon, the geographical location of CO 2 -EOR value chain el-ements (thus different environmental impact due to different ecological sensitivity) and different market conditions (cost of CO 2 , oil price). All of these differences pose a challenge when estimating emissions from CO 2 -EOR projects. The mentioned varieties between CO 2 -EOR projects (and generally CCS/CCUS projects), but also the lack of standardized methods for estimating the full lifecycle emissions resulting from CO 2 -EOR projects, result in various uncertainties and wide flexibilities on how to estimate emissions from these kinds of projects.
Narrow-analysis of case-specific data could be done, but generally, there is a lack of appropriate lifecycle emission estimation methodologies specific to CO 2 -EOR projects (CCS/CCUS projects). In addition, due to the mentioned specifics, in order to estimate the full lifecycle emissions resulting from CO 2 -EOR projects, normalization and a set of benchmark information should be done, which will allow the cross-referencing of CO 2 -EOR projects and its comparison to other climate-mitigation strategies. Pointing out the mentioned differentiation and giving an overview of large-scale CO 2 -EOR projects gives useful information for the future development of standardized methods for estimating the full lifecycle emissions resulting from CO 2 -EOR projects.

Conclusions
CCUS will have an important role in achieving the Paris Amendment goal, as it has proven the potential to deliver significant emission reductions across the energy sector. Even though there are many technologies considered as CCUS, at the moment, the only profitable CCUS projects are large-scale CO 2 -EOR projects, which along with the sequestration of greenhouse gas, resulting in the production of additional value, i.e., incremental oil.
Due to the increasing global crude oil demand caused by economic growth in developing countries and rising needs in the transport sector, especially in market segments with poor or no fuel alternatives (such as aviation), the petroleum industry through the EOR projects could be an option which gives both, energy security and lower emissions.
According to the KAPSARC data source, in 2018, there were 23 large-scale CO 2 -EOR projects in different implementation phases. Most of the projects were in North America utilizing CO 2 from natural gas processing. Considering the number of projects in the definition/evaluation phase and the CO 2 capture capacity of these projects, CO 2 -EOR projects have a significant potential to play an important role in mitigating climate change in China.
However, besides using CO 2 for commercial activity, the main aim of the CCUS projects is CO 2 sequestration. They do not necessarily result in overall net negative emissions due to the fact that the CO 2 retention time significantly differs among the projects ranging from one year, in case of fuel generation, to up to millions of years, in case of carbonation.
With regard to CO 2 -EOR projects, all the conducted studies on lifecycle emissions have shown substantial benefits in CO 2 emission reduction. Studies have shown that CO 2 -EOR lifecycle emissions for every barrel of incremental oil produced are 37% less than in the case of conventional oil production methods. The practice has shown that about 60% of the CO 2 , injected with the purpose of a solvent used for driving the production of residual oil, remains trapped in the reservoir pore space, while 40% of it is reproduced with oil production. Ultimately, if a closed-loop injection system is applied, which is a common case when CO 2 is a commodity that must be purchased or when it is generated as waste during natural gas processing, up to 95% of the cumulatively injected CO 2 within the CO 2 -EOR project remains permanently sequestrated in the oil reservoir.
When considering lifecycle emissions of CO 2 -EOR projects, within the "gate-to-gate" (only CO 2 -EOR activities), the most carbon (and energy) intensive component is gas compression. When conducting "gate-to-grave", and especially when conducting "cradleto-grave" lifecycle emission analysis, due to various possible variants of all the processes involved within all the segments covered by the analysis (upstream-CO 2 generation, CO 2 -EOR activities and downstream-utilization of the produced oil), and the lack of LCA methodologies specific for CO 2 -EOR projects (and CCUS/CCS projects in general), emission assessment is quite complex resulting in various uncertainties and wide flexibilities, which impedes the cross-referencing and comparison of CO 2 -EOR projects to other climatemitigation strategies.