Potential for Non-thermal Chemical Augmented Waterflood for Producing Viscous Oils

Abstract

Chemical Enhanced Oil Recovery (EOR) has regained its attention because of high oil price and the depletion of conventional oil reservoirs. This process is more complex than the primary and secondary recovery and requires detailed engineering design for a successful field-scale application. An alkaline/co-solvent/polymer (ACP) formulation was developed and corefloods were performed for a cost efficient alternative to alkaline/surfactant/polymer floods. Alkali reacts with acidic components of heavy oil (i.e. 170 cp in-situ viscosities) to form natural soap and significantly reduce the interfacial tension, which allows producing residual oil not contacted by waterflood or polymer flood alone. Polymer provides mobility control to drive chemical slug and oil bank. Co-solvent helps to improve the compatibility between in-situ soap and polymer and to reduce microemulsion viscosity. An impressive recovery of 70% of the waterflood residual oil saturation was achieved from an outcrop core where the remaining oil saturation after the ACP flood was reduced to only 13.5%. The results were promising with very low chemical utilization. UTCHEM reservoir simulator was used to model the coreflood experiment to obtain parameters for pilot scale simulations. Geological model was based on unconsolidated reservoir sand with multiple seven spot well patterns. However, facility capacity and field logistics, reservoir heterogeneity as well as mixing and dispersion effects might prevent the design followed in coreflood to be directly scaled for field implementation. Field-scale sensitivity simulations were conducted to optimize the design. The influence of chemical mass, slug size, polymer pre-flush, and injection rates on ultimate oil recovery was investigated. This research emphasizes the importance of small well spacing and good mobility control on recovery efficiency. The in-situ soap generated from alkali-naphthenic acid reaction not only mobilizes residual oil to increase oil recovery, but also enhances water relative permeability to increase injectivity. The paper discusses a cost effective chemical flooding design with an impressive oil recovery by adding relatively small solvent and polymer quantities to injected water. The potential for producing residual oil of the viscous oil is demonstrated in both the coreflood and pilot-scale simulations.

A Mechanistic Integrated Geochemical and Chemical Flooding Tool for Alkaline/Surfactant/Polymer Floods

“…Polymer is responsible for the mobility control and co-solvent is added to the slug to make the in-situ soap compatible with the polymer injected and also to reduce the microemulsion viscosity (Xu et al, 2013;Fortenberry et al, 2013). In this process no synthetic surfactant is injected and the alkaline-oil reaction is intended to provide the surfactant in-situ.…”

“…In this process no synthetic surfactant is injected and the alkaline-oil reaction is intended to provide the surfactant in-situ. We use UTCHEM-IPhreeqc ("phreeqc.dat" database is used) and model the "PCN-1" coreflood reported by Xu et al (2013). It seems that this process is applicable in high acidic crude oil with relatively fresh water.…”

“…It seems that this process is applicable in high acidic crude oil with relatively fresh water. can be found in Xu et al (2013). We use UTCHEM-IPhreeqc ("phreeqc.dat" database is used) and model the "PCN-1" coreflood reported by Xu et al (2013).…”

“…We use UTCHEM-IPhreeqc ("phreeqc.dat" database is used) and model the "PCN-1" coreflood reported by Xu et al (2013). We significantly improved the match for the pressure drop compared with the work of Xu (2012) and Xu et al (2013). Water and oil viscosities at the reservoir conditions are 0.53 and 170 cp, respectively.…”

“…Injecting high amount of alkaline makes the brine salinity high (Peru and Lorenz, 1990;Mohammadi, 2008;Fortenberry et al, 2013). Several researchers have reported successful laboratory and field pilot studies of the ASP flooding (Wanchao et al, 1995;Shutang et al, 1995;Al-Hashim et al, 1996;Demin et al, 1997;Qu et al, 1998;Vargo et al, 1999;Demin et al, 1999;Qiao et al, 2000;Manrique et al, 2000;Yang et al, 2003;Pitts et al, 2006;Mohammadi, 2008;Xu, 2012;Cheng et al, 2012). It seems that the AP flooding can be applied only in reservoirs with low salinity brine.…”