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Cyclic CO2 injection

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Cyclic CO2 (huff-n-puff) injection is an Enhanced oil recovery (E.O.R.) process based on the injection of CO2 (huff stage) into the producing formation, followed by a shut-in period where the injected gas dissolves into the oil, swelling it, and reduces its viscosity. After this soaking stage, the production is restarted (puff stage), increasing oil production from a partially depleted reservoir [1]

Process stages

The Cyclic CO2 process is divided into three stages:

Injection stage

CO2 is injected into the target formation at a higher rate. Pushes part of the mobile oil and water into a further location in the reservoir, reducing water saturation near the wellbore, therefore, increasing the relative permeability of the oil.[2] The injection stage is short compared with the other two stages. At the end of the injection stage, the reservoir pressure will be higher than the initial reservoir pressure.

Soaking stage

In the soaking stage, the well is shut-in, allowing the CO2 dissolution and diffusion processes, resulting in oil swelling, increment in the oil saturation and relative permeability, and reduced viscosity.[2] The reaction between CO2 and oil is slow; that's why a longer duration of the soaking stage and a high volume of CO2 are necessary to achieve the higher recovery of incremental oil.

Production stage

The free CO2 (which did not dissolve into the oil or brine in the soaking stage) is produced as a gas phase. Then, the swelled oil energized by the CO2 dissolved is produced; some oil and brine from distant locations within the reservoir area are also produced due to the pressure drop's driving force. At the surface, both phases will be separated, reducing the oil volume.[2]

Schematic of the CO2 huff 'n' puff.[2]


Cyclic CO2 injection is an E.O.R. process based on swelling and reduction of viscosity which frames it into the immiscible oil recovery. It also can be pointed out that the Solubility of the CO2 in oil is the most influential factor in the increment of oil production.

This E.O.R. system can be applied to moderately heavy oil reservoirs and shallower light oil reservoirs, which do not meet the requirements for miscibility, being located at less than 915 m depths or with oil gravities below 25 °API.[3]

Fig. 2: Effect of reservoir temperature and pressure on CO2.[3]

CO2 Solubility in oil

The CO2 will dissolve into oil through mass transfer, expanding and driving the oil out of the pores to the production well when the pressure is declined in the production stage. [2] CO2 solubility is a function of pressure, temperature and oil gravity[3]. It increases with pressure and API gravity and decreases with temperature. With higher CO2 Solubility, a higher recovery factor is observed.

Viscosity reduction

CO2 dissolution reduces the oil viscosity. This fluid property is more sensitive to temperature. On the other hand, increasing the pressure increases the oil's viscosity and density, not a desired effect.[2]

Fig. 3: Viscosity reduction ratio and CO2 Solubility at different P&T.[2]

Oil swelling

When CO2 is injected into the heavy oil reservoir, it dissolves into the heavy oil, expanding the oil volume. This increase in volume leads a drainage force, pushing water out of the pore space; also, oil swelling can increase the oil saturation, which increases oil relative permeability.[2]

The oil swelling factor is affected by pressure, temperature and oil composition, as shown in fig. 4. Also, the oil swelling factor is proportional to the CO2 Solubility.

Fig. 4: Oil swelling factor at different P&T.[2]

Diffusion coefficient

The diffusion coefficient controls the diffusion rate and the amount of CO2 that becomes dissolved in the oil. This coefficient is related to pressure, temperature, and oil composition.[2] The effect of pressure over the diffusion coefficient is significant. However, if the pressure increase to a high level, the oil viscosity and density will increase, causing a reduction in the diffusion coefficient.

Fig. 5: CO2 Solubility and diffusion coefficient at different P&T.[2]


Cyclic CO2 injection has the following benefits over the other forms of tertiary recovery methods.

  1. Cyclic CO2 injection is a cost-effective method.
  2. Cyclic CO2 injection application is useful in heavy-oil reservoirs [4].
  3. It successfully recovered incremental oil in light-oil reservoirs with gravities ranging from 23 to 30° API[4].
  4. It effectively displaces the water in the water-flood reservoir, resulting in recovering the residual oil in light-oil reservoirs[5].
  5. The cyclic CO2 injection process provides relative permeability advantages[5].
  6. It improves the well productivity by reducing oil viscosity, removing near bore well damage and oil swelling due to CO2 dissolution [6].
  7. The injected CO2 is produced over the life of the project (ranging from 8 to 100%), rather than all at once in the first days of production [4].


Cyclic CO2 injection has the following limitations over the other forms of tertiary recovery methods.

  1. There should be no mechanical issues with the well, i.e. production casing, packers, wellhead, and X-mas tree need to be in good shape[7].
  2. The well should have a good production baseline [7].
  3. A corrosion inhibition system should be in place to counter the corrosion effects of CO2.
  4. Incremental oil recoveries are higher in the first CO2 cycles as higher residual oil is available, and it tends to go down in the subsequent cycles[8].
  5. The higher the volume of CO2 injected, the higher the recovery of incremental oil will be.[4].
  6. The project's cost tends to increase with the depth of the reservoir; therefore, shallow reservoirs are more cost-effective[7].
  7. For the light-oil sandstone reservoirs with adequate reservoir drive, the CO2 migration radius should be a maximum of 150 ft and should be less than 150 ft when reservoir energy is minimal [7].
  8. Higher recoveries are expected in the presence of mobile-water or free-gas saturation and an adequate drive mechanism[7].

See also

Cyclic steam stimulation


  1. Sanaei, Alireza, Abouie, Ali, Tagavifar, Mohsen, and Kamy Sepehrnoori. "Comprehensive Study of Gas Cycling in the Bakken Shale." Paper presented at the SPE/AAPG/SEG Unconventional Resources Technology Conference, Houston, Texas, USA, July 2018.
  2. 2.00 2.01 2.02 2.03 2.04 2.05 2.06 2.07 2.08 2.09 2.10 Xiang Zhou, Qingwang Yuan, Xiaolong Peng, Fanhua Zeng, Liehui Zhang. “A critical review of the CO2 huff ‘n’ puff process for enhanced heavy oil recovery”. Fuel, Volume 215, 2018, Pages 813-824, ISSN 0016-2361.
  3. 3.0 3.1 3.2 Perera, Mandadige S.A.; Gamage, Ranjith P.; Rathnaweera, Tharaka D.; Ranathunga, Ashani S.; Koay, Andrew; Choi, Xavier. 2016. "A Review of CO2-Enhanced Oil Recovery with a Simulated Sensitivity Analysis" Energies 9, no. 7: 481.
  4. 4.0 4.1 4.2 4.3 Haskin, Helen K., and Robert B. Alston. "An Evaluation of CO2 Huff 'n' Puff Tests in Texas." J Pet Technol 41 (1989): 177–184.
  5. 5.0 5.1 Monger, T.G., and J.M. Coma. "A Laboratory and Field Evaluation of the CO2 Huff 'n' Puff Process for Light-Oil Recovery." SPE Res Eng 3 (1988): 1168–1176.  
  6. Mohammed-Singh, Lorna & Singhal, Ashok & Sim, Steve. (2006). “Screening Criteria for CO2 Huff 'n' Puff Operations”. 10.2118/100044-MS.
  7. 7.0 7.1 7.2 7.3 7.4 Thomas, G. and T. Monger-Mcclure. “Feasibility of Cyclic CO2 Injection for Light-Oil Recovery.” SPE Reservoir Engineering 6 (1991): 179-184.
  8. Alshmakhy, A.. , and B.. Maini. "A Follow-Up Recovery Method After Cold Heavy Oil Production Cyclic CO2 Injection." Paper presented at the SPE Heavy Oil Conference Canada, Calgary, Alberta, Canada, June 2012.