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Gas foam flooding
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
Oil recovery/production process in general comprises of three stages.
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.
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, 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
Gas Flooding, especially CO2 gas flooding has become an significant miscible conventional (light) oil recovery process. The basic mechanisms tthat allow this process to improve oil reccovery include: reduced oil viscosity, decreased interfacial tension and miscibility with oil. A major problem in gas flooding is its high mobility, which results in viscous fingering and gravity override. The drawbacks of gas flooding minimized by injecting a surfactant solution alternating with CO2 (SAG) and by co-injection of surfactant solution and CO2 for the generation of foam in the reservoir which would reduce the mobility of gas and increase the sweep efficiency  .
Foam based Gas flooding as a substitute
Foam reduces the gas mobility and divert the gas to areas of the reservoirs, where CO2 alone would not reach.
Injection of a viscous phase, e.g., Foam was also 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.
The crude oil recovery is increased, when the gas is forced to enter low permeability zones while the foam blocks the high permeability zones.
Foam propagation in porous media
The efficiency of foam to reduce gas mobility (i.e., foam strength) and its stability are key considerations for all intended field applications. Various parameters have been used to determine the efficiency of foam in porous media, and one common parameter is the mobility reduction factor (MRF):
Mobility Reduction Factor (MRF) = ΔPfoam / ΔPno-foam
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, injected 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 “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:
- Injection rate
- Brine salinity
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 significantly affected by the foaming agent. Selection of appropriate surfactant/foaming agent should be done based on its capability of generating good quality of foam at reservoir conditions. Another important consideration is that the selected surfactant should have adsorption and decomposition losses.
Stabilizers are used to enhance the compatibility and stability of the generated foam with respect to the reservoir pressure and temperature.
|Surfactant Name(s)||Authors||Surfactant Type||Fluid|
|Chaser CD 1045||Tsau and Heller, 1992;Heller 1994; Yaghoobi and Heller,
1994; Yaghoobi et al., 1998; Chang and Grigg, 1999; Bai et al., 2005;Baiet al.,201O
|AlipalCD 128||Dellinger et al., 1984;Casteel and Djabbara,1988;Holm and Garrison, 1988; Hudgins and Chuna, 1990·Alkan et al. 1991||Anionic||C02-Foam|
|Chaser CD 1040||Yaghoobi and Heller, 1994||Anionic||C02-Foam|
|Chaser CD 1050||Tsau and Heller, 1992; Yaqhoobi and Heller, 1994||Non-ionic||C02-Foam|
|NES-25,AvanelS30||Tsau and Heller, 1992||Anionic||C02-Foam|
|Shell Enordet X2001||Lee and Heller, 1990; Lee,
Heller and Hoefer, 1991; Yaghoobi and Heller, 1994; Kuhlman et al., 2000
|Sherex Varian CAS||Lee and Heller, 1988; Lee and Heller, 1990||Anionic||C02-Foam|
|Plurafoam N0-2N, Witcolate
|Casteel and Djabbara , 1988||Anionic||C02-Foam|
|S-50,C-10,N-40,0-Sap||Alkan et al., 1991||Anionic/Non-Ionic||C02-Foam|
|TRS 18 and TRS 40 blend||Bae and Petrick, 1977||Anionic||Alkaline-Surfactant|
|AOS C14-C16 Shell AOS||Bertin and Apaydin, 1999||Anionic||C02-Foam|
|AOS||Mohammadi and Tenzer, 1990||Anionic||N2-Foam|
|CRSO 85/66||Di Julio and Emanuel, 1989||Anionic||C02-Foam|
|DOWFAX||Kuhlman et al.,2000||Anionic||C02-Foam|
|Triton X 200 octylphenol
ethoxylate, Neodol 25-9, NEGS
|Witcolate 1247H and 1276, Witconate 3203 and AOS12, Stepanflo 10,Pluronic F-68 EO-PO copolymer, Dowfax 8390,Dow XSS-$4321.05 and
XSS 84321.12, Ethoauad C/12
|Prieditis and Paulett, 1992; Lee
and Heller, 1990
|40 surfactants||Borchardt, 1985||Anionic||C02-Foam|
|5 unknown surfactants||Djabbarah et al., 1990||N/A||N2-Foam|
|AS-40||Chen et al., 1990||N/A||N2-Foam|
|Siponate OS 10||De Vries and Wit, 1990||N/A||N2-Foam|
|AOS 1618,Siponate DS-10,
Neodene 1618, Sioonate A 168
|Patzek and Kolnis, 1990||N/A||N2-Foam|
|ZV 01||Yu et al., 2008||N/A||Air-Foam|
|NEODOL 67-7PO,IOS 15-18,
|Li et al., 2012||Anionic||Air-Foam|
Surfactant Adsorption on 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)
Factors affecting Adsorption:
- Surfactant formulation
- Crude oil and brine compositions
- Rock mineralogy
- Pressure & temperature of reservoir
CO2 versus 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.
Aarra showed that CO2 foam can block water and gas at HPHT conditions in carbonate rocks. Fernø et al. 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.
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. CO2 foam becomes weaker and less stable at harsh conditions of pressure and temperature, which reduces its effectiveness. 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. 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.
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