Investigation Into the Processes Responsible for Heavy Oil Recovery by Alkali-Surfactant Flooding
- Jonathan Luke Bryan (U. of Calgary) | An Thuy Mai (University of Calgary) | Apostolos Kantzas (U. of Calgary)
- Document ID
- Society of Petroleum Engineers
- SPE Symposium on Improved Oil Recovery, 20-23 April, Tulsa, Oklahoma, USA
- Publication Date
- Document Type
- Conference Paper
- 2008. Society of Petroleum Engineers
- 5.4.6 Thermal Methods, 5.3.4 Reduction of Residual Oil Saturation, 5.1 Reservoir Characterisation, 5.4.1 Waterflooding, 5.8.5 Oil Sand, Oil Shale, Bitumen, 2.5.2 Fracturing Materials (Fluids, Proppant), 2.4.3 Sand/Solids Control, 1.6.9 Coring, Fishing, 4.1.2 Separation and Treating, 4.1.5 Processing Equipment, 5.2.1 Phase Behavior and PVT Measurements, 5.4.7 Chemical Flooding Methods (e.g., Polymer, Solvent, Nitrogen, Immiscible CO2, Surfactant, Vapex), 5.5.2 Core Analysis, 4.6 Natural Gas, 5.4.10 Microbial Methods, 5.7.2 Recovery Factors
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This paper describes a suite of alkali-surfactant (AS) floods that were performed in systems containing viscous heavy oil (11,500 mPa×s). The study investigates how AS injection can be used to generate oil and water emulsions, which can in turn lead to improved sweep efficiencies and oil recovery. Data is obtained from core flooding, with in-situ saturation measurements made using low field NMR. This work is applicable to the many heavy oil reservoirs in countries like Canada and Venezuela that contain viscous oil that still has some limited mobility under reservoir conditions. In previous studies, improved oil recovery compared to waterflooding was observed. This work provides additional information that can be used to better understand how chemical injection can lead to oil recovery.
The core floods in this study indicate that emulsification is most efficient when used to block pre-formed water channels and improve the sweep efficiency of the flood. Both O/W and W/O emulsions may form in the same system, even under controlled salinity conditions. The re-distribution of water from the flooded channels into emulsified droplets in the oil is at least partially responsible for the pressure increase seen in these systems. W/O emulsification is accompanied by wettability alteration, as evidenced by the NMR spectra obtained. After the chemical flood is completed, it may be possible to restore the original water wet condition of the rock, which can provide potential for future non-thermal improved oil recovery.
Several countries in the world, notably Canada and Venezuela, contain significant deposits of heavy oil and bitumen. These oil sands are characterized as unconsolidated, high porosity and permeability reservoirs. The viscosity of the oil in place may range from tens to millions of mPa×s (cP) at reservoir conditions, and the oil densities will approach or even be higher than that of water. Due to the significant size of these oil sand deposits, coupled with rising oil prices and demand, international interest is now shifting towards recovery of this heavy oil and bitumen.
Heavy oil reservoirs are a special subset of the oil sands, whereby the oil viscosity at reservoir temperature and pressure ranges from around 50 - 50,000 mPa×s. This oil, while still highly viscous, has some limited mobility at reservoir conditions. The oil may also contain some dissolved solution gas, and initially it may be possible to recover a fraction of the oil through primary production. Recent estimates by the AEUB1 put the primary recovery of heavy oil at an average of around 5% OOIP, meaning that at the end of primary production there are still significant oil resources remaining as potential for secondary and tertiary recovery. Unfortunately, many of the reservoirs in Canada are relatively small or thin, and were possibly disturbed during primary production. As a result, reservoirs these are not prime candidates for expensive thermal or hydrocarbon solvent enhanced oil recovery technologies. Therefore, in-expensive (non-thermal) methods of recovering the oil have to be considered.
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