Evaluation and Economical Feasibility of Polymer-Assisted Surfactant Flooding for the Gullfaks Field, Norway

Abstract

This paper presents parts of the work performed to develop and qualify a polymer-assisted surfactant flooding (PASF) system for economical use in the Gullfaks Field, Norway. The paper addresses experimental work done in the laboratory, numerical simulation of PASF, and the evaluation of the potential for PASF in full-field scale.The experimental part comprises core-flooding experiments at different temperatures, pressures, and gas/oil ratios (GOR) to optimize the PASF system for the Gullfaks Brent formation conditions. The surfactant in the PASF system is a branched sulphonate (5,000 ppm) and xanthan (500 ppm). The surfactant-polymer slug is followed by a slug of xanthan (500 ppm) for mobility control. No cosolvent is used. In coreflood experiments more than 70% of the waterflood residual oil was recovered.Using reservoir simulation, a suitable pilot area was found in the Brent reservoir. Additional results from simulations were the amount of chemicals, the time needed for the pilot test, and additional oil recovery.Much effort was put into estimating the full field PASF potential. First, the areas of the field where PASF possibly could be used were selected. Key factors were existing and planned well locations, production data, and long-term production forecasts. Then, the amount of chemicals needed and the expected technical efficiency for each area were calculated. To verify these calculations, an area of the field containing two possible injection wells and three producers was selected for a simulation study. This area was considered the most promising area for PASF.The main conclusion from this work is that, with the present crude-oil price and chemical costs, the PASF process is not economically attractive for use in the Gullfaks field, mainly because the residual oil was considerably lower than believed at project start.

Temperature Effects on Surfactant-Aided Imbibition Into Fractured Carbonates

“…It depends on the partition of surfactant between aqueous and oleic phases, which depends on the type of crude oil and surfactant. Earlier studies have shown both increasing and decreasing trends of optimal salinity with an increase in temperature (Skauge and Forland 1990;Maldal et al 1998;Healy et al 1976). …”

“…Healy et al (1976) also found an increase in optimal salinity with an increase in temperature for alkyl sulfonates with a mixture of paraffinic and aromatic oils. Maldal et al (1998) observed a shift from Winsor II− through III toward II+ with an increase in temperature for branched ethoxylated sulfonate surfactants with Gullfaks-field oil. The shift depends on the type of oil, surfactant, and brine composition.…”

“…Phase behavior of surfactant/oil/water mixture, wettability, interfacial tension (IFT), viscosity of oil, surfactant diffusivity, and imbibition rates can be affected by temperature. The effect of temperature on the phase behavior for both anionic and nonionic surfactants (Skauge and Forland 1990;Maldal et al 1998;Healy et al 1976;Saito and Shinoda 1970) has been reported in literature. Skauge and Forland (1990) found the shift of phase behavior from Winsor II+ to Winsor II− (i.e., an increase in optimal salinity with an increase in temperature) for alkylbenzene sulfonate and secondary alkane sulfonate with a sodium chloride brine, heptanes, and n-butanol (as cosolvent) system.…”

Low-Tension Polymer Flooding Using a Short-Hydrophobe Surfactant for Heavy Oil Recovery

“…The improvement in the oil displacement efficiency of polymer flooding was studied by adding surfactants at low concentrations and was referred to as LTP flooding in the 1990s , before the technological advancements that led to the current practice of SP and ASP flooding, such as new surfactants, their formulations, and salinity gradient. LTP flooding does not use the salinity gradient that is often necessary to use ultralow IFT (10 –3 dyn/cm) microemulsions in SP and ASP flooding.…”