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Gas Foam Flooding is an [[Enhanced oil recovery (EOR)|Enhanced oil recovery]] process in which gas (widely CO2 and N2), is injected into the reservoir to recover the remainder oil left behind after the primary recovery.  
Gas Foam Flooding is an [[Enhanced oil recovery (EOR)|Enhanced oil recovery]] process in which gas (widely CO2 and N2), is injected into the reservoir to recover the remainder oil left behind after the primary recovery.  


==='''Oil recovery stages:'''===
==='''Oil recovery stages'''===
[[File:Oil recovery.jpg|thumb|Fig-1: Oil recovery stages and technologies <ref>Vishnyakov, V., Suleimanov, B., Salmanov, A., & Zeynalov, E. (2020). ''Primer on enhanced oil recovery''. Cambridge, MA: Gulf Professional Publishing, an imprint of Elsevier. </ref>|alt=]]Oil recovery/production process in general comprises of three stages.  
[[File:Oil recovery.jpg|thumb|Fig-1: Oil recovery stages and technologies <ref>Vishnyakov, V., Suleimanov, B., Salmanov, A., & Zeynalov, E. (2020). ''Primer on enhanced oil recovery''. Cambridge, MA: Gulf Professional Publishing, an imprint of Elsevier. </ref>|alt=]]Oil recovery/production process in general comprises of three stages.  


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==='''Gas flooding and its drawbacks:'''===
==='''Gas flooding and its drawbacks'''===
[[File:Gas-mobility-control.jpg|thumb|624x624px|Fig-2: Gas Foam Flooding Comparison to Gas Flooding |alt=]]Gas Flooding, majorly CO2 gas flooding has been a significant miscible conventional (light) oil recovery process. In which mechanisms such as reduced oil viscosity, decreased [[interfacial tension]] and miscibility with oil, are improved, contributing towards improved oil recovery. Drawbacks from gas flooding, viscous fingering and gas channeling were minimized by injecting surfactant solution alternating CO2 (SAG) and co-injection of surfactant solution and CO2 were used for the generation of foam in the reservoir which would reduce the mobility of gas and increase the sweep efficiency. (Pang, 2010; Zhang et al., 2013; Chen et al., 2014; Ren et al., 2013) There are two main reasons for this: first, in heavy oil reservoirs CO2 lacks acceptable sweep efficiency due to a large viscosity contrast between CO2 and oil; second, CO2 diffusion is very slow in such viscous oils, hence, it takes an extended period for CO2 to meet the bypassed oil after breakthrough.   
[[File:Gas-mobility-control.jpg|thumb|624x624px|Fig-2: Gas Foam Flooding Comparison to Gas Flooding |alt=]]Gas Flooding, majorly CO2 gas flooding has been a significant miscible conventional (light) oil recovery process. In which mechanisms such as reduced oil viscosity, decreased [[interfacial tension]] and miscibility with oil, are improved, contributing towards improved oil recovery. Drawbacks from gas flooding, viscous fingering and gas channeling were minimized by injecting surfactant solution alternating CO2 (SAG) and co-injection of surfactant solution and CO2 were used for the generation of foam in the reservoir which would reduce the mobility of gas and increase the sweep efficiency. (Pang, 2010; Zhang et al., 2013; Chen et al., 2014; Ren et al., 2013) There are two main reasons for this: first, in heavy oil reservoirs CO2 lacks acceptable sweep efficiency due to a large viscosity contrast between CO2 and oil; second, CO2 diffusion is very slow in such viscous oils, hence, it takes an extended period for CO2 to meet the bypassed oil after breakthrough.   


==='''Foam based Gas flooding as a substitute:'''===
==='''Foam based Gas flooding as a substitute'''===
Foam is defined as a dispersion of gas in a medium (liquid). (Hirasaki 1989; Kovscek and Radke 1994). In 1950’s, Foam Flooding was proposed to improve the sweep efficiency of oil and early gas breakthroughs. These were the two problems associated with the traditional gas flooding.  
Foam is defined as a dispersion of gas in a medium (liquid). (Hirasaki 1989; Kovscek and Radke 1994). In 1950’s, Foam Flooding was proposed to improve the sweep efficiency of oil and early gas breakthroughs. These were the two problems associated with the traditional gas flooding.  


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==='''Foam propagation in porous media:'''===
==='''Foam propagation in porous media'''===
The efficiency of foam to reduce gas mobility (i.e., foam strength) and its stability are key questions for all intended field applications. Various parameters have been used to determine the efficiency of foam in porous media (Heller 1994), and one common parameter is the mobility reduction factor (MRF):  
The efficiency of foam to reduce gas mobility (i.e., foam strength) and its stability are key questions for all intended field applications. Various parameters have been used to determine the efficiency of foam in porous media (Heller 1994), and one common parameter is the mobility reduction factor (MRF):  


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==='''Adsorption:'''===
==='''Adsorption'''===
Surfactant Adsorption into the rock surface is a major problem associated in Foam based Gas Flooding. Adsorption will destabilize the foam and reduces the concentration of surfactant in the injected fluid. (15)  
Surfactant Adsorption into the rock surface is a major problem associated in Foam based Gas Flooding. Adsorption will destabilize the foam and reduces the concentration of surfactant in the injected fluid. (15)  



Revision as of 03:06, 16 March 2021

Gas Foam Flooding is an Enhanced oil recovery process in which gas (widely CO2 and N2), is injected into the reservoir to recover the remainder oil left behind after the primary recovery.  

Oil recovery stages

Fig-1: Oil recovery stages and technologies [1]

Oil recovery/production process in general comprises of three stages.

Primary recovery

Primary recovery is the initial stage of oil and gas production from the reservoir, where the oil displacement occurs through the reservoir built-in pressures. Oil recovered under primary recovery is typically around 10% of the oil in the reservoir.

Secondary recovery

The second stage in hydrocarbon production in which water or gas is injected into the reservoir to maintain/develop reservoir pressure enough to produce hydrocarbon in place. The combination of primary and secondary recovery stages sums up to 15-40% initial oil in place.

Tertiary recovery

Tertiary recovery, often referred to as Enhanced Oil Recovery.  There are three main type of Enhanced Oil Recovery techniques namely, Chemical Flooding, Gas Injection and Thermal recovery. Oil recovery done in stage is either by restoring the pressures in the reservoir or by improving the oil displacement through various techniques.  

According to US Department of Energy, 75% of oil is still left in the reservoir after primary and secondary recovery. Further enhancement of oil production up to 75% is done in tertiary recovery or EOR-Enhanced Oil Recovery.

Gas flooding and its drawbacks

Fig-2: Gas Foam Flooding Comparison to Gas Flooding

Gas Flooding, majorly CO2 gas flooding has been a significant miscible conventional (light) oil recovery process. In which mechanisms such as reduced oil viscosity, decreased interfacial tension and miscibility with oil, are improved, contributing towards improved oil recovery. Drawbacks from gas flooding, viscous fingering and gas channeling were minimized by injecting surfactant solution alternating CO2 (SAG) and co-injection of surfactant solution and CO2 were used for the generation of foam in the reservoir which would reduce the mobility of gas and increase the sweep efficiency. (Pang, 2010; Zhang et al., 2013; Chen et al., 2014; Ren et al., 2013) There are two main reasons for this: first, in heavy oil reservoirs CO2 lacks acceptable sweep efficiency due to a large viscosity contrast between CO2 and oil; second, CO2 diffusion is very slow in such viscous oils, hence, it takes an extended period for CO2 to meet the bypassed oil after breakthrough.

Foam based Gas flooding as a substitute

Foam is defined as a dispersion of gas in a medium (liquid). (Hirasaki 1989; Kovscek and Radke 1994). In 1950’s, Foam Flooding was proposed to improve the sweep efficiency of oil and early gas breakthroughs. These were the two problems associated with the traditional gas flooding.  

Several research studies have been conducted on the performance of CO2 foam to control the mobility of CO2 gas and enhancing the sweep efficiency in heterogeneous reservoirs. (Khalil and Asghari, 2006; Sohrabi and Farzaneh, 2013; Zhang et al., 2014a)

Foam reduces the gas mobility and avert the gas to areas of the reservoirs, where CO2 has not reached.  

Injection of a viscous phase, e.g., Foam was used for the recovery of heavy oil with immiscible displacement. The foam injected after CO2 injection could displace the mixture of oil and co2, which furthermore improves the heavy oil recovery.

Crude oil recovery is increased, when the gas is forced to enter low permeable zones while the foam blocks the high permeability zones. (22)

Foam propagation in porous media

The efficiency of foam to reduce gas mobility (i.e., foam strength) and its stability are key questions for all intended field applications. Various parameters have been used to determine the efficiency of foam in porous media (Heller 1994), and one common parameter is the mobility reduction factor (MRF):



where ΔPfoam and ΔPno-foam are the measured differential pressure across the porous medium with and without foam, respectively, at the same gas/water ratio. A high MRF corresponds to strong foam.

Foam stability and mobility reduction characteristics depend on the properties of rock and fluids and process design parameters such as formation permeability, injection foam quality and the size of the chemical slug. The effects of these parameters on the performance of the foam flooding process needs to be ascertained to determine its optimal potential for EOR.

Hirasaki (1989) defined foam in porous media as 2 “a dispersion of a gas in a liquid such that liquid phase is continuous and at least some part of the gas phase is made of discontinuous by thin films called lamellae.”

Parameters effecting Foam Mobility Control:

  1. Permeability
  2. Injection rate
  3. Pressure
  4. Temperature
  5. Brine salinity
  6. Oil

Additives used

Surfactant or foaming agent

Surfactants or Foaming agents plays a vital role in foam generation and stability of foam in porous media. Interfacial tension between gas and liquid which effects the values of capillary forces are majorly affected by the foaming agent. Selection of appropriate surfactant/foaming agent should be done based on of its capability of generation of foam with respect to its quantity and quality at reservoir conditions. The main important function is that the selected surfactant should have less adsorption and decomposition losses.

Foam stabilizer

Stabilizers are used to enhance the compatibility and stability of the generated foam with respect to the reservoir pressure and temperature.

Adsorption

Surfactant Adsorption into the rock surface is a major problem associated in Foam based Gas Flooding. Adsorption will destabilize the foam and reduces the concentration of surfactant in the injected fluid. (15)

Functions of Adsorption:

  • Surfactant formulation
  • Crude oil and brine compositions
  • Rock mineralogy
  • Pressure & temperature of reservoir


CO2 and N2 Foams in Foam based Gas Flooding in EOR:

In foam EOR processes, CO2 and N2 foams are the most widely used. The inherent difference between CO2 and N2 accounts for the variation in properties of foam formed by these gases. These differences are magnified with an increase in pressure, especially at supercritical pressure (for CO2, 1100 psi at 31.1 °C) where CO2 is unable to generate foam or generates very weak foam. However, N2 remains in the subcritical state and generates strong foam even at higher pressures. The inability of CO2 to generate foam/strong foam leads to an increase in mobility resulting in poor sweep efficiency. These difficulties can be overcome by replacing part of CO2 with N2, and foam can be generated by a mixture of N2 and CO2 gases. Although there are many studies comparing CO2 and N2 foams, the properties of mixed CO2/N2 foam for EOR have not been investigated.

CO2 foams

Aarra (16) showed that CO2 foam can block water and gas at HPHT conditions in carbonate rocks. Fernø et al. (17) studied the ability of pure CO2 and CO2 foam to be applied for EOR in fractured carbonate systems. It was concluded that CO2 foam injection increased oil recovery when compared to the injection of pure CO2 in fractured core samples. This can be due to better viscous displacement plus diffusion.

N2 foams

CO2 at supercritical conditions produces weak and unstable foam. Supercritical CO2 has properties midway between the liquid and gas. It acts like a supercritical fluid above its critical conditions to fill a container like a gas but with a density like a liquid. Foam is not a stable fluid system. Especially, CO2 foam becomes weaker and less stable at harsh conditions of pressure and temperature, which reduces its usage. Compared to N2, CO2 foam is less stable at typical reservoir conditions, which is considered a challenge to select the foam agents. Several studies have been carried out for comparing CO2 and N2 foam in relation to EOR. (18, 19, 20) It is difficult to compare CO2 foam and N2 foam without considering the effect of surfactant, porous media, solubility, and range of pressure and temperature. Some scholars used the same surfactant for comparing CO2 and N2 foams. (21)

References

  1. Vishnyakov, V., Suleimanov, B., Salmanov, A., & Zeynalov, E. (2020). Primer on enhanced oil recovery. Cambridge, MA: Gulf Professional Publishing, an imprint of Elsevier.