Open access peer-reviewed chapter

CO2 Miscible Flooding for Enhanced Oil Recovery

Written By

Abdelaziz Nasr El-hoshoudy and Saad Desouky

Submitted: January 22nd, 2018 Reviewed: May 23rd, 2018 Published: September 12th, 2018

DOI: 10.5772/intechopen.79082

Chapter metrics overview

2,004 Chapter Downloads

View Full Metrics


Carbon capture aims to mitigate the emission of CO2 by capturing it at the point of combustion then storing it in geological reservoirs or applied through enhanced oil recovery (EOR) in a technology known as miscible flooding, so reduce CO2 atmospheric emissions. Miscible CO2-EOR employs supercritical CO2 to displace oil from a depleted oil reservoir. CO2 improve oil recovery by dissolving in, swelling, and reducing the oil viscosity. Hydrocarbon gases (natural gas and flue gas) used for miscible oil displacement in some large reservoirs. These displacements may simply amount to “pressure maintenance” in the reservoir. In such flooding techniques, the minimum miscibility pressure determined through multiple contact experiments and swelling test to determine the optimum injection conditions.


  • miscible flooding
  • enhanced oil recovery
  • swelling test
  • minimum miscibility pressure

1. Background

CO2 concentration in atmosphere increases due to the industrial revolution that attributed to the combustion of fossil fuels [1]. CO2 is responsible of 64% of environmental pollution [1], so there is a dire need to mitigate its concentration to avoid global warming emissions. CO2 miscible flooding in crude oil reservoirs is a currently successful technique to reduce its amount in the atmosphere, in addition to increasing the mobility of the oil and, consequently, increase the reservoir productivity [2]. It is preferred other than hydrocarbon gases since it does not only increase oil recovery but also causes a reduction of greenhouse gas emissions [3]. Moreover, it is a cheap technology as an ultimate long-term geologic storage solution for CO2 owing to its economic productivity from incremental oil production offsetting the cost of carbon sequestration, and exhibit high displacement efficiency and the potential for environmental contamination decrease through its disposal in the petroleum reservoir [1, 4]. This chapter aims to provide basic technical information concerning enhanced oil recovery by CO2 flooding.


2. Enhanced oil recovery (EOR) processes

Owing to increased oil demand, improved oil recovery become a challenging task [3], since fossil fuels are the dominant source of the global energy supply [2] and represent about 85% of energy needs. Crude oil production occurs through three distinct phases [5, 6, 7, 8, 9]. The first stage is known as primary recovery, in which oil is recovered by natural reservoir energy including expansion of rock, fluid and dissolved gases, gravity drainage, and aquifer influx, or combination of these factors, which drive the hydrocarbon fluids from the reservoir to the wellbores. Primary oil recoveries range between 5 and 20% [10] of the original oil-in-place (OOIP). As reservoir pressure declines with the sustained production process, so the reservoir pressure must be built-up by injecting either water or natural gas, which drive reservoir fluid to wellbore [11]. This stage is known as secondary oil recovery, in which the recovered oil estimated to be in the range of 20–40% of the OOIP [10]. At the end of secondary recovery, a significant amount of residual oil remains in the reservoir and becomes the target for additional recovery using tertiary recovery or enhanced oil recovery (EOR) methods. EOR refers to the displacement of the remaining oil in the reservoir through injection of materials not normally present in the reservoir [10, 12, 13, 14, 15, 16, 17]. Generally, EOR processes comprise the following three categories:

2.1. Thermal EOR

Injection of steam has historically been the most widely applied EOR method. Heat from steam or hot water dramatically reduces heavy oils viscosity, thus improving its flow. The process involves cyclic steam injection (“huff and puff,” where steam is first injected, followed by oil production from the same well); Continuous steam injection (where steam injected into wells drives oil to separate production wells); hot water injection, and steam assisted gravity drainage (SAGD) using horizontal wells. Another set of thermal methods include, in situ combustion or fire flooding are currently implemented [18, 19, 20].

2.2. Miscible EOR

Miscible EOR employs supercritical CO2 to displace oil from a depleted oil reservoir. CO2 improve oil recovery by dissolving in, swelling, and reducing the viscosity of the oil. CO2 is a cheap injection source for increasing recovery factor by the rate of 1–2$/Mscf [21]. Most CO2 flooding processes occur in United States [22]. Hydrocarbon gases (natural gas and flue gas) in addition to compressed nitrogen used for miscible oil displacement in high deep reservoirs. These displacements may simply amount to “pressure maintenance” in the reservoir [23, 24, 25].

2.3. Chemical EOR

Chemical flooding was, up to 2000s, a less common EOR method than thermal and gas flooding, but now, huge projects are retrieved. The chemical flooding processes involve the injection of three kinds of chemicals; alkaline, surfactant and polymer (soluble and cross-linked polymers), in addition to other chemicals such as foaming agents, acids and solvents [26] and/or combination of alkaline-surfactant-polymer flooding (ASP) [27]. In the polymer flooding method, water-soluble polymers aimed to shut-off the high-permeability areas of the reservoir and increase injected water viscosity to increase the swept areas in the reservoir [28, 29] leading to a more efficient displacement of moderately viscous oils. Addition of a surfactant to the polymer formulation may, under very specific circumstances, reduce oil–water interfacial tension (IFT) and hence remobilizing the trapped oil [30], changing surface wettability, so enhance the oil production. For some oils, alkaline may convert some naphthenic acids within the oil to surfactants that increase oil recovery. The alkaline may also play a beneficial role in reducing surfactant retention in the rock [31, 32, 33, 34].


3. Fundamentals and mechanism of CO2 flooding

Improvement of oil recovery occurs through different techniques, one of which is CO2 flooding in low permeable and light-oil reservoirs [35, 36], as it can increase recovery factor from 10 to 20% [37]. Moreover, it reduces atmospheric gas emissions through CO2 storage [38]. Gas miscible flooding implies that the displacing gas is miscible with reservoir oil either at first contact or after multiple contacts, which in turn improve the volumetric sweeping and displacement efficiencies (Ev and Ed) respectively [39, 40]. A transition zone will develop between the reservoir oil and displacing gas, where the miscibility of the injected gas depend on reservoir pressure, temperature, and oil properties [41, 42]. CO2 miscible flooding comprises two mechanisms.

3.1. Miscible flooding

Miscible flooding depends on mobilizing the oil light components, reduction of oil viscosity, the vaporization and swelling of the oil, and the lowering of interfacial tension [41]. The injected CO2 completely dissolve through crude oil at the minimum miscibility pressure (MMP) which determined experimentally through slim-tube tests or by mathematical correlations [3, 43, 44] and defined as, the pressure at which more than 80% of original oil-in-place (OOIP) is recovered at CO2 breakthrough [45]. However, on an industrial scale, an oil recovery of at least 90% at 1.2 pore volume of CO2 injected is used as a rule-of-thumb for estimating MMP [46, 47]. When the reservoir pressure is above the MMP, miscibility between CO2 and reservoir oil is achieved through multiple-contact or dynamic miscibility, where the intermediate and higher molecular weight hydrocarbons from the reservoir oil vaporize into the CO2 (vaporized gas-drive process) and part of the injected CO2 dissolves into the oil (condensed gas-drive process) [48]. This mass transfer between the oil and CO2 allows the two phases to become completely miscible without any interface and helps to develop a transition zone [49] that is miscible with oil and CO2. CO2 miscible flooding comprises; 1 first contact; vaporizing gas drive, and condensing gas drive [10].

  1. First contact: in which miscible solvents mix with reservoir oil in all proportions and the mixture remains in one phase. Either through single or multiple contacts, and resulting in much improved oil recovery [50].

  2. The vaporizing gas-drive process (high-pressure gas drive): achieves dynamic miscibility by in situ vaporization of the intermediate-molecular-weight hydrocarbons from the reservoir oil through injection of lean gases or CO2 [51].

  3. The condensing gas-drive process (enriched gas drive): achieves dynamic miscibility by in situ transfer of intermediate molecular weight hydrocarbons from rich solvent to lean reservoir oil through condensation process [52].

3.2. Immiscible flooding

Immiscible flooding depends on oil viscosity reduction, oil phase swelling, the extraction of lighter components, and the fluid drive [53]. When the reservoir pressure is below the MMP or the reservoir oil composition is not favorable, the CO2 and oil will not form a single phase (i.e., immiscible). However, CO2 will dissolve in the oil causing oil swelling, viscosity reduction and solution gas derive which in turn improve sweeping efficiency and facilitate further oil recovery [54]. Like hydrocarbon gases, CO2 miscibility through crude oil increases with pressure and decreases with temperature [55, 56].


4. Properties of CO2

In order to fully understand CO2-EOR flooding, it is important to look at the properties of CO2 and the fundamentals of the CO2-EOR process. Under ambient conditions, CO2 is a colorless, odorless gas and about 1.5 times heavier than air. CO2 is (2–10 times) more soluble in oil than in the water. CO2 increases the water viscosity and forms carbonate acid, which has a beneficial effect on shale and carbonate rocks [57]. Its properties under standard and critical conditions are summarized in Table 1. Above critical pressures and temperatures, CO2 is in the supercritical state and forms a phase whose density is close to that of a liquid, even though its viscosity remains quite low (0.05–0.08 cp). This dense CO2phase can extract hydrocarbon components from oil more easily than gaseous CO2 [49].

Properties at standard conditions (14.7 psia, 0°C)
Molecular weight44.010 g/mol
Specific gravity1.529
Density1.95 kg/m3
Viscosity0.0137 mPa/s
Critical properties
Critical pressure (Pc)1070.6 psia
Critical temperature (Tc)87.98°F
Critical volume (Vc)94 cm3/mol
Critical viscosity (μc)0.0335 cp

Table 1.

Properties of CO2 under standard and critical conditions.


5. CO2 flooding and injection designs

Depending on the reservoir geology, fluid and rock properties, the CO2 flooding involves the following;

5.1. Continuous CO2 injection

This process requires continuous CO2 injection with no other fluid. Sometimes a lighter gas, such as nitrogen, follows CO2 injection to maximize gravity segregation.

5.2. Continuous CO2 injection followed with water

This process is the same as the continuous CO2 injection process except for chase water that follows the total injected CO2 slug volume.

5.3. Conventional water-alternating-gas (WAG) followed with water

In this process, a predetermined volume of CO2 is injected in cycles alternating with equal volumes of water. The water alternating with CO2 injection helps overcome the gas override and reduces the CO2 channeling consequently, improving overall CO2 sweep efficiency.

5.4. Tapered WAG

This design is similar in concept to the conventional WAG but with a gradual reduction in the injected CO2 volume relative to the water volume.

5.5. WAG followed with gas

This process is a conventional WAG process followed by a chase of less expensive gas (e.g., air or nitrogen) after the full CO2 slug volume has been injected.


6. CO2-EOR flooding projects and case studies

Several literatures stated about implementation of CO2 and carbonated water to improve oil recovery since 1951 [45, 54, 58, 59], owing to its availability in adequate amounts from both natural and industrial sources [60]. The first field-wide application occurred in 1972 at the SACROC (Scurry Area Canyon Reef Operators Committee) unit in the Permian Basin, where the CO2 was transported via a 200-mile-long pipeline from the Delaware-Val Verde Basin [10]. Hashemi and Pouranfard [1] reported about the investigation of immiscible miscible CO2 injection southwest of Iranian oil field, which has two reservoirs: Gurpi and a shallower Asmari reservoir. Main reservoir in this field is the Asmari formation with Oligocene and Miocene ages, which is divided into seven zones. Therefore, only the Asmari formation has been producing oil at commercial scale. The Asmari formation in this field consists of fractured carbonates with a low permeability matrix. The matrix has a porosity and permeability of about 0.088% and 3.4 md, respectively [1]. They concluded that the minimum miscibility pressure (MMP) was 4630 psia, The optimum injection rates for immiscible and miscible CO2 injection scenarios were 17,000 and 30,000 Mscf/day, respectively and oil recovery factor reach 36.59% [1]. Al-Aryani and others [61] have reported on the first CO2-EOR pilot test in the Middle East where pulsed neutron logging was used to monitor the performance of a CO2 flood in one of the largest oil fields in Abu Dhabi, United Arab Emirates. The results of this test will be viewed with great interest based on the fact that it will have a significant impact on the application of CO2-EOR in many oil-rich countries in the Middle East with the potential for very large additional oil recoveries. In India, a CO2-EOR feasibility study was implemented in an oil field on the west coast, but the results are not yet publically available [62]. In China, there is ongoing research and pilot testing of CO2-EOR and carbon sequestration in the Jilin oil field with plans to expand to other fields [63]. As of 2012, there were 15 CO2-EOR projects outside of the United States—six in Canada, three in Brazil, five in Trinidad, and one in Turkey [64]. Of the six CO2-EOR miscible projects in Canada, the Weyburn project is the most significant because it was the first project with the primary objective of injecting CO2 for additional oil recovery as well as for carbon sequestration to help mitigate climate change. In recent years, there have been some serious efforts by Scottish Carbon Capture & Storage (SCCS), the Scottish Government, and other companies to investigate the possible application of CO2-EOR in the North Sea. This interest is based on the potential for additional oil recovery from depleted oil fields using CO2 captured from power plants and industry [10]. The objective is to gain a better understanding of the use of CO2 in EOR operations with the goal of extending the producing life of North Sea oil fields using CO2 captured from large emitters, such as power plants and industrial facilities, and permanently store the greenhouse gas in offshore oil reservoirs. It is estimated that there is the potential to recover 24 billion barrels of additional oil in the North Sea using the CO2-EOR process. About 60 active miscible CO2 projects were in operation in the United States in 1996, whereas in Canada, hydrocarbon miscible floods reach nearly ∼40 active projects [35, 65]. Most CO2-flooding projects carried out in the United States in Colorado, Louisiana, Mississippi, New Mexico, Michigan, Oklahoma, Texas, Utah, and Wyoming. During 2014, about 22 companies implemented CO2 flooding projects; where 128 projects contributed about 126 million tons of oil [66], applied through carbonate and sandstone reservoirs with a percentage of 55 and 37% respectively, while the other 6% were implemented in tripolite reservoirs [67]. The range of porosity is from 4 to 29.5% with a permeability of 100 mD. The main operators and their productions reported in Table 2. The increased implementation of CO2 flooding projects resort to its availability from natural and industrial sources in addition to its relatively low cost as a displacing agent compared to other alternatives [68]. It is observed that the outcome of these projects summarized in Table 2, where the recovery factor ranged from 0.15 to 36.37%. The reservoirs properties are summarized in Table 3.

OperatorNo. of projectsImproved production (×104 tons)Recovered oil (%)
Kinder Morgan3138.3410.94
Denbury Resources1886.826.87
Merit Energy771.125.63
Breitburn Energy536.872.92
Whiting Petroleum124.511.94
XTO Energy Inc.413.431.06
Chaparral Energy89.180.73
Core Energy91.900.15

Table 2.

CO2 miscible flooding operator and production dataset [66, 69, 70].

Permeability, mD27001444.35
API gravity27453837
Viscosity, cp0.461.81.3
Temperature, °F83260108.5133.9
Depth, ft115011,95055006107.3
Oil saturation (% PV)26.3894649.6
Net thickness, ft1526890110
Minimum miscibility pressure (MMP), psia102034521987.52058.4

Table 3.

Properties of reservoirs subjected to CO2 flooding.


7. Screening criteria for CO2 flooding

Screening criteria for miscible CO2 flooding comprise reservoir depth, pressure and temperature, minimum miscibility pressure (MMP), residual oil saturation, net pay thickness, crude oil gravity, and viscosity in addition to permeability, porosity, and reservoir heterogeneity [40]. In preliminary screening, according to National Petroleum Council, the optimum reservoir criteria for CO2 miscible flooding [64, 71] are summarized in Table 4. Any deviation from these criteria would depend on the size of the reservoir and potential hydrocarbon recovery. For example when reservoir temperatures are greater than 120°F, additional pressure ranges from 200 to 500 psi is required to achieve miscibility. The density of CO2 depends on the injection depth, which controls the ambient temperature and pressure and range from 0.6–0.8 g/cc [72]. The CO2 should be injected at depth greater than 800 m, where it is in a dense phase (either liquid or supercritical) [2]. High saline reservoirs are more susceptible to CO2 storage than low salinity reservoirs.

CriteriaOptimum condition
Depth, ft2500 [73]–3000 [74]
Reservoir temperature, °F<120
Reservoir pressure, psi>3000
Total dissolved solids (TDS)<10,000 mg/L
Oil gravityMedium to light oils (27–39°API)
Oil viscosity, cp<3
Reservoir typeCarbonate reservoirs preferred than sandstone one
Minimum miscibility pressure (MMP), psi1300–2500
Oil saturation>20% [73]
Net pay thickness, ft75–137
Permeability>10 mD

Table 4.

Optimum screening criteria for CO2 miscible flooding.

All reservoir lithology, including carbonate and siliciclastic are appropriate for CO2-EOR flooding as long as they have interconnected pore space for fluid accumulation and flow. Proper reservoir characterization leads to accurate estimates of OOIP and a convenient evaluation of reservoir behavior. The OOIP calculated volumetrically, by the following equation;


7758, multiplying factor, (barrels/acre-feet); A, reservoir area,(acres);h; average net reservoir thickness, (feet); Ø; average porosity of formation; Soi; initial oil saturation in pore space; Boi; oil formation volume factor at initial reservoir pressure (bbl/STB).


8. CO2-miscible flooding performance and simulation

Before conducting a CO2-flooding, its miscibility with the reservoir is determined through measurement of MMP. After that, a pilot test is conducted to check the success of the CO2-EOR process on a small scale in the field. If all results are positive, reservoir simulation is carried out to (a) scale-up the EOR process to an entire oil field and (b) define the optimum design of the WAG ratio and hydrocarbon pore volume injection volumes for maximum oil recovery [75]. The performance of a flooding process evaluated by exploring the slug of CO2 and water, the performance of oil-production wells, gas-oil ratio and water cut, and the injection wells for fluid distribution among various reservoir layers, since these parameters greatly effect on the recovery factor [76].


9. Operational aspect

In order to implement a successful CO2-miscible flooding several parameters are considered;

9.1. CO2 source

There are three possible sources of CO2: (1) natural hydrocarbon gas reservoirs containing CO2 as an impurity (generally less than 25%), (2) industrial or anthropogenic sources with wide variation of CO2 percentage in the effluent like power plants and so on [2], and (3) natural CO2 reservoirs [49].

9.2. Surface facilities

The facility requirements for CO2-EOR include the following items.

  1. CO2 extraction: it is extracted from the separator gas, which begins to show increasing quantities of CO2 after its breakthrough in producing wells [77].

  2. CO2 processing: it is purified to specification after its extraction from the separator gas and is dehydrated before compression [78].

  3. CO2 compression: it is compressed to raise its pressure for injection [79].

9.3. Technological challenges

Technical challenges of CO2 flooding can be summarized in the following [80].

  1. Increasing CO2 injection volumes,

  2. Optimizing flood design and well placement for extracting more of the residual oil,

  3. Improving the mobility ratio by increasing the viscosity of water by use of polymers, and

  4. Extending miscibility by reducing the miscibility pressure through the use of liquefied petroleum gas (LPG).


10. Conclusion

The primary and secondary oil recovery produces about 20–40% of the OOIP [48]. Consequently, there is a huge amount of potentially unrecovered oil left in the reservoir, which becomes the target for suitable EOR processes. One of the widely implemented EOR processes is CO2-miscible flooding which recovers high amounts of crude oil and reduces environmental pollution results from gas emissions. CO2 can be injected either as a continuous stream, water-alternating gas (WAG). Implementation of successful CO2 miscible flooding require an accurate investigation of reservoir screening criteria comprising reservoir porosity and permeability, API gravity, oil viscosity, reservoir temperature, depth, oil saturation, and net pay thickness.


  1. 1. Fath AH, Pouranfard A-R. Evaluation of miscible and immiscible CO2 injection in one of the Iranian oil fields. Egyptian Journal of Petroleum. 2014;23(3):255-270
  2. 2. Herzog H. Carbon Dioxide Capture and Storage. USA: Helm Hepburn, Oxford University press; 2009
  3. 3. Karkevandi-Talkhooncheh A, Rostami A, Hemmati-Sarapardeh A, Ahmadi M, Husein MM, Dabir B. Modeling minimum miscibility pressure during pure and impure CO2 flooding using hybrid of radial basis function neural network and evolutionary techniques. Fuel. 2018;220:270-282
  4. 4. Bui M, Adjiman CS, Bardow A, Anthony EJ, Boston A, Brown S, et al. Carbon capture and storage (CCS): The way forward. Energy & Environmental Science; 2018;11:1062-1176
  5. 5. El-hoshoudy A, Desouky S, Betiha M, Alsabagh A. Use of 1-vinyl imidazole based surfmers for preparation of polyacrylamide–SiO2 nanocomposite through aza-Michael addition copolymerization reaction for rock wettability alteration. Fuel. 2016;170:161-175
  6. 6. El-hoshoudy A. Quaternary ammonium based surfmer-co-acrylamide polymers for altering carbonate rock wettability during water flooding. Journal of Molecular Liquids. 2018;250:35-43
  7. 7. El-hoshoudy A, Desouky S, Al-Sabagh A, Betiha M, MY E-k MS. Evaluation of solution and rheological properties for hydrophobically associated polyacrylamide copolymer as a promised enhanced oil recovery candidate. Egyptian Journal of Petroleum. 2017;26(3):779-785
  8. 8. El-Hoshoudy A, Desouky S, Elkady M, Alsabagh A, Betiha M, MS. Investigation of optimum polymerization conditions for synthesis of cross-linked polyacrylamide-amphoteric surfmer nanocomposites for polymer flooding in sandstone reservoirs. International Journal of Polymer Science. 2015;2015
  9. 9. El-hoshoudy A, Desouky S, Al-sabagh A, El-kady M, Betiha M, Mahmoud S. Synthesis and characterization of polyacrylamide crosslinked copolymer for enhanced oil recovery and rock wettability alteration. International Journal of Oil, Gas and Coal Engineering. 2015;3(4):43-55
  10. 10. Verma MK. Fundamentals of Carbon Dioxide-Enhanced Oil Recovery (CO2-EOR): A Supporting Document of the Assessment Methodology for Hydrocarbon Recovery Using CO2-EOR Associated with Carbon Sequestration. Washington, DC: US Department of the Interior, US Geological Survey; 2015
  11. 11. El-hoshoudy A, Desouky S, Elkady M, Alsabagh A, Betiha M, Mahmoud S. Hydrophobically associated polymers for wettability alteration and enhanced oil recovery—Article review. Egyptian Journal of Petroleum. 2016;26:757-762
  12. 12. Terry RE, Rogers JB, Craft BC. Applied Petroleum Reservoir Engineering. USA: Pearson Education; 2013
  13. 13. Dusseault M. Comparing Venezuelan and Canadian heavy oil and tar sands. In: Canadian International Petroleum Conference; Petroleum Society of Canada, Calgary, Alberta, Canada, 2001
  14. 14. Arps JJ. Estimation of Primary Oil Reserves. one Petro. 1956;207:182-191
  15. 15. Dake LP. The Practice of Reservoir Engineering (Revised Edition). Amestrdam, The Netherlands: Elsevier; 2001
  16. 16. Kovscek A. Screening criteria for CO2 storage in oil reservoirs. Petroleum Science and Technology. 2002;20(7–8):841-866
  17. 17. Archer JS, Wall CG. Petroleum Engineering: Principles and Practice. London: Springer Science & Business Media; 2012
  18. 18. Muraza O, Galadima A. Aquathermolysis of heavy oil: A review and perspective on catalyst development. Fuel. 2015;157:219-231
  19. 19. Wan T. Evaluation of the EOR Potential in Shale Oil Reservoirs by Cyclic Gas Injection. USA: Texas Tech University Libraries; 2013
  20. 20. Babadagli T, Sahin S, Kalfa U, Celebioglu D, Karabakal U, Topguder NNS. Development of heavy oil fractured carbonate Bati Raman field: Evaluation of steam injection potential and improving ongoing CO2 injection. SPE Annual Technical Conference and Exhibition. Society of Petroleum Engineers; 2008
  21. 21. Manrique EJ, Muci VE, Gurfinkel ME. EOR field experiences in carbonate reservoirs in the United States. SPE Reservoir Evaluation & Engineering. 2007;10(06):667-686
  22. 22. Taber J, Martin F, Seright R. EOR screening criteria revisited—Part 2: Applications and impact of oil prices. SPE Reservoir Engineering. 1997;12(03):199-206
  23. 23. Plasynski S, Litynski J, McIlvried H, Srivastava R. Progress and new developments in carbon capture and storage. Critical Reviews in Plant Science. 2009;28(3):123-138
  24. 24. Farajzadeh R, Andrianov A, Bruining H, Zitha PL. Comparative study of CO2 and N2 foams in porous media at low and high pressure−temperatures. Industrial & Engineering Chemistry Research. 2009;48(9):4542-4552
  25. 25. Li S, Qiao C, Zhang C, Li Z. Determination of diffusion coefficients of supercritical CO2 under tight oil reservoir conditions with pressure-decay method. Journal of CO2 Utilization. 2018;24:430-443
  26. 26. Schramm G. A Practical Approach to Rheology and Rheometry. Karlsruhe: Haake; 1994
  27. 27. Abidin A, Puspasari T, Nugroho W. Polymers for enhanced oil recovery technology. Procedia Chemistry. 2012;4:11-16
  28. 28. Sorbie K, Clifford P. The inclusion of molecular diffusion effects in the network modelling of hydrodynamic dispersion in porous media. Chemical Engineering Science. 1991;46(10):2525-2542
  29. 29. El-hoshoudy AN, Desouky SM. Synthesis and evaluation of acryloylated starch-g-poly (acrylamide/vinylmethacrylate/1-vinyl-2-pyrrolidone) crosslinked terpolymer functionalized by dimethylphenylvinylsilane derivative as a novel polymer-flooding agent. International Journal of Biological Macromolecules. 2018;116:434-442
  30. 30. Haywood V, Yu TS, Huang NC, Lucas WJ. Phloem long-distance trafficking of GIBBERELLIC ACID-INSENSITIVE RNA regulates leaf development. The Plant Journal. 2005;42(1):49-68
  31. 31. Olajire AA. Review of ASP EOR (alkaline surfactant polymer enhanced oil recovery) technology in the petroleum industry: Prospects and challenges. Energy. 2014;77:963-982
  32. 32. Liu S, Miller CA, Li RF, Hirasaki G. Alkaline/surfactant/polymer processes: Wide range of conditions for good recovery. SPE Journal. 2010;15(02):282-293
  33. 33. Kumar S, Panigrahi P, Saw RK, Mandal A. Interfacial interaction of cationic surfactants and its effect on wettability alteration of oil-wet carbonate rock. Energy & Fuels. 2016;30(4):2846-2857
  34. 34. Chen I-C, Akbulut M. Nanoscale dynamics of heavy oil recovery using surfactant floods. Energy & Fuels. 2012;26(12):7176-7182
  35. 35. Song Z, Zhu W, Wang X, Guo S. 2-D pore-scale experimental investigations of asphaltene deposition and heavy oil recovery by CO2 flooding. Energy & Fuels. 2018;32(3):3194-3201
  36. 36. Zhou X, Yuan Q, Peng X, Zeng F, Zhang L. A critical review of the CO2 huff ‘n’puff process for enhanced heavy oil recovery. Fuel. 2018;215:813-824
  37. 37. Kulkarni MM. Immiscible and Miscible Gas-Oil Displacements in Porous Media. MSc Thesis. Louisiana State University and Agricultural and Mechanical College. 2003
  38. 38. Bachu S, Adams J. Sequestration of CO2 in geological media in response to climate change: Capacity of deep saline aquifers to sequester CO2 in solution. Energy Conversion and Management. 2003;44(20):3151-3175
  39. 39. Claridge E. Prediction of recovery in unstable miscible flooding. Society of Petroleum Engineers Journal. 1972;12(02):143-155
  40. 40. Mathiassen OM. CO2 as Injection Gas for Enhanced Oil Recovery and Estimation of the Potential on the Norwegian Continental Shelf. Trondheim, Norwegian University of Science and Technology (NTNU) Norway; 2003
  41. 41. Thomas S. Enhanced oil recovery—An overview. Oil & Gas Science and Technology-Revue de l'IFP. 2008;63(1):9-19
  42. 42. Jessen K, Kovscek AR, Orr FM Jr. Increasing CO2 storage in oil recovery. Energy Conversion and Management. 2005;46(2):293-311
  43. 43. An E-h, Desouky S. An Empirical Correlation for Estimation of Formation Volume Factor of Gas Condensate Reservoirs at Separator Conditions
  44. 44. An E-h, Desouky S. Numerical Prediction of Oil Formation Volume Factor at Bubble Point for Black and Volatile Oil Reservoirs Using Non-Linear Regression Models
  45. 45. Holm L, Josendal V. Mechanisms of oil displacement by carbon dioxide. Journal of Petroleum Technology. 1974;26(12):1427-1438
  46. 46. Yellig W, Determination MR. Prediction of CO2 minimum miscibility pressures (includes associated paper 8876). Journal of Petroleum Technology. 1980;32(01):160-168
  47. 47. Taber JJ, Martin F, Seright R. EOR screening criteria revisited—Part 1: Introduction to screening criteria and enhanced recovery field projects. SPE Reservoir Engineering. 1997;12(03):189-198
  48. 48. Merchant D. Life beyond 80—A look at conventional wag recovery beyond 80% HCPV injection in CO2 tertiary floods. Carbon Management Technology Conference. Carbon Management Technology Conference; 2015
  49. 49. Jarrell PM, Fox CE, Stein MH, Webb SL. Practical Aspects of CO2 Flooding. TX: Society of Petroleum Engineers Richardson; 2002
  50. 50. Bondor P. Applications of carbon dioxide in enhanced oil recovery. Energy Conversion and Management. 1992;33(5–8):579-586
  51. 51. Stalkup FI Jr. Status of miscible displacement. Journal of Petroleum Technology. 1983;35(04):815-826
  52. 52. Holm LW. Miscible displacement (1987 PEH Chapter 45). Petroleum Engineering Handbook. USA: Society of Petroleum Engineers; 1987
  53. 53. Holm LW, Josendal VA. Effect of oil composition on miscible-type displacement by carbon dioxide. Society of Petroleum Engineers Journal. 1982;22(01):87-98
  54. 54. Martin JW. Additional oil production through flooding with carbonated water. Producers Monthly. 1951;15(7):18-22
  55. 55. Simon R, Graue D. Generalized correlations for predicting solubility, swelling and viscosity behavior of CO2-crude oil systems. Journal of Petroleum Technology. 1965;17(01):102-106
  56. 56. Leung LC. Numerical evaluation of the effect of simultaneous steam and carbon dioxide injection on the recovery of heavy oil. Journal of Petroleum Technology. 1983;35(09):1,591-1,1,9
  57. 57. Solomon S. Carbon dioxide storage: Geological security and environmental issues–Case study on the sleipner gas field in Norway. Bellona Report. 2007. p. 128
  58. 58. Mosavat N, Torabi F. Experimental evaluation of the performance of carbonated water injection (CWI) under various operating conditions in light oil systems. Fuel. 2014;123:274-284
  59. 59. Holm WL. Evolution of the carbon dioxide flooding processes. Journal of Petroleum Technology. 1987;39(11):1337-1342
  60. 60. Ayirala S, Yousef A. A state-of-the-art review to develop injection-water-chemistry requirement guidelines for IOR/EOR projects. SPE Production & Operations. 2015;30(01):26-42
  61. 61. Aryani A, Mohamed F, Obeidi A, Brahmakulam JV, Ramamoorthy R. Pulsed neutron monitoring of the first CO2 EOR pilot in the Middle East. In: SPE Middle East Oil and Gas Show and Conference; Society of Petroleum Engineers. 2011
  62. 62. Srivastava RP, Vedanti N, Dimri V, Akervol I, Bergmo P, Biram R. CO2-EOR: A feasibility study of an Indian oil field. In: 2012 SEG Annual Meeting; Society of Exploration Geophysicists. 2012
  63. 63. Chang CW-K. Stumbling toward Capitalism: The State, Global Production Networks, and the Unexpected Emergence of China's Independent Auto Industry. Berkeley: University of California; 2011
  64. 64. Koottungal L. Worldwide EOR survey. Oil & Gas Journal. 2012, 2012;110:57-69
  65. 65. Khormali A, Sharifov AR, Torba DI. The control of asphaltene precipitation in oil wells. Petroleum Science and Technology. 2018;36(6):443-449
  66. 66. Jishun Q, Haishui H, Xiaolei L. Application and enlightenment of carbon dioxide flooding in the United States of America. Petroleum Exploration and Development. 2015;42(2):232-240
  67. 67. Boot-Handford ME, Abanades JC, Anthony EJ, Blunt MJ, Brandani S, Mac Dowell N, et al. Carbon capture and storage update. Energy & Environmental Science. 2014;7(1):130-189
  68. 68. Goodyear SG, Koster M, Marriott K, Paterson A, Sipkema AW, Young I. Moving CO2 EOR offshore. In: SPE Enhanced Oil Recovery Conference; Society of Petroleum Engineers. 2011
  69. 69. Yin M. CO2 Miscible Flooding Application and Screening Criteria. Missouri University of Science and Technology; 2015
  70. 70. Olea RA. Carbon Dioxide Enhanced Oil Recovery Performance According to the Literature. US Geological Survey; 2017
  71. 71. Kuuskraa V. QC updates carbon dioxide projects in OGJ's enhanced oil recovery survey. Oil & Gas Journal. 2012;110(7):72
  72. 72. Sheppard M. Carbon Capture and Sequestration. Schlumberger, Paper 17; 2007
  73. 73. Gao P, Towler BF, Pan G. Strategies for evaluation of the CO2 miscible flooding process. In: Abu Dhabi International Petroleum Exhibition and Conference; Society of Petroleum Engineers. 2010
  74. 74. Arshad A, Al-Majed AA, Menouar H, Muhammadain AM, Mtawaa B. Carbon dioxide (CO2) miscible flooding in tight oil reservoirs: A case study. In: Kuwait International Petroleum Conference and Exhibition; Society of Petroleum Engineers. 2009
  75. 75. Peterson CA, Pearson EJ, Chodur VT, Pereira C. Beaver Creek Madison CO2 enhanced recovery project case history. In: SPE Improved Oil Recovery Symposium; Society of Petroleum Engineers; Riverton, Wyoming. 2012
  76. 76. Perera MSA, Gamage RP, Rathnaweera TD, Ranathunga AS, Koay A, Choi X. A review of CO2-enhanced oil recovery with a simulated sensitivity analysis. Energies. 2016;9(7):481
  77. 77. Holm L. Carbon Dioxide Solvent Flooding for Increased Oil Recovery. OnePetro; 1959;216:225-231
  78. 78. Posch S, Haider M. Optimization of CO2 compression and purification units (CO2CPU) for CCS power plants. Fuel. 2012;101:254-263
  79. 79. Benson SM, Orr FM. Carbon dioxide capture and storage. MRS Bulletin. 2008;33(4):303-305
  80. 80. Papadopoulou M. Numerical Simulation Study of Low-Tension-Gas (LTG) Flooding for Enhanced Oil Recovery in Tight Formations. The University of Texas at Austin; 2017

Written By

Abdelaziz Nasr El-hoshoudy and Saad Desouky

Submitted: January 22nd, 2018 Reviewed: May 23rd, 2018 Published: September 12th, 2018