The recovery of oil from a reservoir is generally divided into: Primary, Secondary and Tertiary recovery, termed as such because they are frequently applied in that chronological order. Tertiary Recovery or Enhanced Oil Recovery (EOR) processes include all those methods that mobilize or recover the oil left behind or that cannot be produced economically by the conventional methods. Among the EOR processes, Miscible Gas Injection is the second largest EOR process, next only to thermal processes used in heavy oil fields. CO2 injection for EOR has been proved to be superior to other miscible gases like N2, inert/flue gases, hydrocarbon gases etc. CO2 is preferred because it is cheaper, has higher density, and offers environmental benefits of CO2sequestration.
CO2 flooding is an effective and leading EOR technique for light and medium crude oils. It has the potential to prolong the production lives of light or medium oil fields nearing depletion under waterflooding by 15-20 years, and may recover an additional 15 to 25% of the Original Oil in Place (OOIP). CO2 is not strictly miscible with crude oil, but under the right conditions it can displace oil nearly as efficiently as a truly miscible solvent. The commonly-recognized oil recovery mechanisms for CO2flooding are oil viscosity reduction, oil-swelling effect, the IFT reduction, light-hydrocarbons extraction, immiscible and miscible displacements.
Although the microscopic displacement efficiency is high in CO2 flooding, the volumetric sweep efficiency is not as high. This results in low overall oil recovery efficiency. Miscible CO2 floods typically recover 10%–20% of the OOIP via the injection of a volume of dense CO2 equivalent to 80% of the hydrocarbon pore volume (HCPV). In case of immiscible CO2 floods recover only 5%–10% OOIP being less efficient than miscible. The result is: 35%–65% of the OOIP remains unrecovered after CO2flooding.
CO2 is generally injected into the reservoir as a supercritical fluid (Sc-CO2) to recover additional oil. The viscosity of Sc-CO2 (~ 0.05–0.10 cP) is lower by more than an order of magnitude than either of reservoir water and most crude oils, resulting in a number of conformance and mobility issues, and also instability of the displacement front. Adverse mobility ratio causes fingers of CO2 to grow from the displacement front, leading to premature CO2 breakthrough, bypassing of the oil and inefficient oil recovery. Additionally, lower density CO2 relative to the oil promotes migration of CO2toward the upper part of the pay zone, a condition known as gravity override, causes even more oil to be missed out.
Mobility and conformance issues are the most serious concerns associated with CO2 flooding. Some of the techniques employed to overcome CO2 mobility and conformance control problems are: Water-alternating-with-gas (WAG); Mechanical techniques (e.g. infill drilling, horizontal wells, and various completion practices and cement or packers for isolation, etc.; Direct CO2 Thickener; CO2-foams etc.
Foam has been extensively used in improved and enhanced oil recovery processes in the petroleum industry over decades. Foam display some favourable behaviour that are beneficial to the EOR: (i) with the presence of foaming agent in a porous medium, gaseous and aqueous phases could approach a favourable mobility ratio; (ii) selective fluid diversion from thief zones to lower permeability regions can take place; (iii) causes apparent increase in gas viscosity; (iv) existence of surfactant can lower water-oil Interfacial Tension (IFT) making capillary held oil mobile.
Foaming the displacing phases can improved the sweep efficiency and oil recovery. Gas flow in form of bubbles separated by thin films called lamellae exhibits more resistance produced not only by viscous shear stresses in thin films between the pore walls and the gas-liquid interface, but also by the forces required to push lamellae through constricted pore throats.
CO2-Foam can be formed in the porous media by the co-injection or alternate injection of surfactant solution and CO2. CO2 foam increases the apparent viscosity of displacing fluid and improves the oil recovery by decreasing mobility. Studies have reported that CO2 foam can selectively reduce mobility of CO2 by a greater fraction in higher than in lower permeability regions. A number of surfactants have been found to be useful for CO2 mobility reduction in porous media. The primary requirements for CO2 mobility control through foam is a surfactant with proper chemical stability, adsorption characteristics and foaming or emulsifying capability. Anionic, nonionic, and amphoteric surfactants have been more commonly found useful for CO2foam flooding of sandstone reservoirs.
During foam flooding process, clay minerals in rock matrix adsorbed the surfactants and were detrimental process. So the Alkali-Surfactant-Gas (ASG) injection process was conceptualised, using alkali as a clay stabilizer. Presence of alkali assists in increasing the efficiency of the process by reducing surfactant adsorption and in-situ soap generation with resulting lower IFT without adding extra surfactant.
The literature review suggest that although a good number of works have been done on CO2 Foam injection for EOR and a few works on the use of Alkali in the ASG process; but the alkali association with CO2 Foam EOR process is not reported yet. In view of this, a systematic experimental study is made on the novel Alkaline/Surfactant/CO2 Foam process to find out whether it meets the requirements of a good EOR and can enhance efficiency over WAG/SAG injection process. The study is carried out on a field of the Upper Assam Basin, India to estimate EOR potential of by CO2 injection and to evaluate the feasibility of immiscible Alkaline/Surfactant/CO2Foam injection as an EOR process. A series of experiments has been performed, including reservoir rock & fluid characterisation, phase behavior, foam stability, and coreflood studies.
The oil field selected is one of the major hydrocarbon producing fields of Upper Assam Basin.. Commercial oil production has been established in Tipams formations of Miocene age, Barails of Oligocene age and Kopilis of Eocene age. As in 2012, the field has Original Oil in Place (OOIP) of 130.11 MMt in Proved but undeveloped (PUD) category. The field has so far produced 14.7 MMt of oil, which works out to 11.3% of proved OIIP. This means that high residual oil saturation of more than 80% makes the field ideal for EOR application. The drive mechanism is depletion drive and pressure maintenance through water injection is followed. The initial reservoir pressure was approximately 3400 psi. The current pressure is approximately 1800 psia, which is lower than the saturation pressure of 2500 psi. The reservoir temperature is approximately 170 0F and the average depth of the producing formation is 8200 ft. The oil producing formations are 4000-4300 ft thick sediments mainly consisting of sandstone with subordinate clay stone and shale deposited in a fluvial environment over a denuded surface of Barails.
The following materials are used for the chemical formulation:
Surfactants: Na-lignosulfonate (by-product of a nearby paper mill), Triton X-100, Alpha Olefin Sulphonate (AOS), Internal Olefin Sulfonate (IOS).
Alkali: Sodium Carbonate, Sodium Metaborate, NaOH
Co-solvent Isopropyl Alcohol
Crude oil, Formation Brine, Porous Media:
Crude oil-brine systems of the producing field of Upper Assam Basin, India is selected; Synthetic formation brine (SFB) is prepared based on field brine compositions. Sandstone core samples collected from depths of 8250 to 11,550 ft are the porous media for the oil displacement experiments.
The average porosity of the core samples is approximately 23% and average permeability of the field is the range of 10-50 mD. The oil is light to medium gravity (24– 350 API) with a viscosity of 0.7 to 1.7 cP. The Resin/Asphaltene ratios of the crude oils are in the stable range (as per Leontaritis, 1989 criteria), being greater than 3. The optimum chemical formulations are prepared based on the IFT, phase behaviour, aqueous stability and foaming tests. These are the promising chemical formulations that performed well in the mentioned experiments exhibiting lowest IFTs, low surfactant retention and capable of recovering residual oil in cores. Core Flood experiments are carried out to validate the chemical formulations and to estimate the residual oil recovery under different injection scenarios.
The general procedure followed during the core flood experiments are:
- Brine saturation: Core was saturated with brine and absolute permeability of core measured.
- Oil Saturation: Oil was flooded to minimum water saturation and relative permeability to oil at residual water saturation calculated.
- Waterflood: Brine was flooded until no more oil will be produced. Relative permeability of brine at residual oil saturation measured.
- Chemical or Gas slug injection: CO2 Flooding, CO2-Foam Flooding, Alkaline-Surfactant-CO2-Foam Flooding.
During these core flood tests the pressure drop across core and oil recovery are recorded. From the core tests results, it was found that immiscible CO2 flooding can lead to improving oil recovery in the reservoirs of Upper Assam Basin, India. It can also be concluded that recovery of residual oil improved by the additional of alkali proving the viability of the immiscible Alkaline/Surfactant/CO2 Foam injection as an EOR process.
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