A New Approach to ASP Flooding in High Saline and Hard Carbonate Reservoirs

Abstract

Chemical Enhanced Oil Recovery (CEOR) has come into focus as a highly effective and versatile EOR method due to recent advances in the technology. However, CEOR particularly Alkali-Surfactant-Polymer (ASP) flooding is challenging in carbonate reservoirs. The main constraints are the undesired minerals such as calcite, dolomite, anhydrite and gypsum consisted of divalent ions. The minerals complex with injected chemicals and form precipitates that cause formation damage and scale formation in wells and surface facilities. This study presents a new Acid-Alkali-Surfactant-Polymer (AASP) flooding formulation as an alternative to conventional ASP flooding. AASP included acrylic acid as a precipitation inhibitor. The new formulation was compatible with the hard brine composition of 59,940 ppm TDS (with 2762 ppm divalent ions) for 30 days at 80 °C. AASP combination also provided acceptable interfacial tension and slug viscosity required for flooding in the presence of hard brine. Additionally, more than 30% Origional Oil in Place (OOIP) was recovered in the natural imbibition tests. Injecting 0.5PV of the optimum AASP formulation slug gave 18.9% OOIP to waterflooding in the coreflood tests. Thus, AASP flooding formulation is viable for suppressing the limitations of ASP flooding in carbonate reservoirs. Although, precipitation inhibitor increases the cost of chemical slug by adding several hundred parts per million (ppm) of inhibitor, significant cost savings will be realized because of the reductions in workover jobs and associated lost of production. Further, AASP flooding formulation also eliminates the need to soften the mixing brine. This will result in expanding the CEOR application to more challenging carbonate reservoirs and reduce the softening cost for mixing water. Introduction The term Chemical EOR is used in the petroleum industry literature to refer to a class of tertiary oil recovery. Chemical EOR is usually prefered after primary recovery (or natural depletion from expansion of reservoir fluids and reservoir compaction) and secondary waterflood recovery. Waterflooding is a process whereby water is injected into a reservoir to provide pressure support and to sweep oil to the production wells. In time, the oil produced as a percentage of total liquids production will decline. Eventually the oil cut will become uneconomical. At this point, the reservoir is considered to be at residual oil saturation to waterflood. The purpose of Chemical EOR is to recover the remaining or residual oil in a reservoir that has had its mobile oil swept and produced during a waterflood. To achieve this objective, oil needs to be contacted and mobilized. Oil can be contacted by improving the sweep efficiency of injected fluids. One way to do improve sweep efficiency is to increase the viscosity of the injected fluid relative to the connate fluids. This provides a more favourable mobility ratio, prevents viscous fingering, and helps to overcome reservoir heterogeneities (Manrique et al., 2010; Al-Mjeni et al., 2011; Manrique et al., 2006). Traditionally, sandstone reservoirs have been the most suitable candidate for chemical EOR applications. However, limited numbers of CEOR application are found in carbonate reservoirs throughout the last decades. The reason is high clay content which cause significant adsorption of surfactant and polymer. Dolomite, anhydrite and gypsum often occur in carbonate reservoirs. These minerals cause alkali consumption and formation of precipitates. Unlike sandstones which are homogeneous, carbonate reservoirs are generally complex in petrophysical characteristics. Therefore, chemical enhanced oil recovery is considered as, less effective in carbonate reservoirs (Manrique et al., 2006; Taber et al., 1997).

Review on Surfactant Flooding: Phase Behavior, Retention, IFT, and Field Applications

“…186,187 Recently acrylic acid has been used in a high-salinity environment to avoid precipitation. 57 The acrylic acid reacts with sodium ions and forms the precipitation inhibitor sodium acrylate, which reacts with mineral divalent ions and prevents the formation of precipitates. 188 Alkalis are used to lower the adsorption on mineral surfaces in soft brines.…”

“…Some clay minerals, such as kaolinite andiIllite, are also present in sandstone formations . Sandstone reservoirs, which are homogeneous, are the most appropriate for cEOR . Carbonate reservoirs, which are estimated to contain 60% of the remaining oil, are composed of calcite (CaCO 3 ), dolomite (CaMg­(CO 3 ) 2 ), anhydrite (CaSO 4 ), gypsum (CaSO 4 ·H 2 O), and magnesite (MgCO 3 ) rocks.…”

“…Although carbonate reservoirs have a great potential for the application of tertiary recovery techniques, EOR research associated with carbonate reservoirs is limited due to many technical challenges. Only a few reports on the application of cEOR in carbonate reservoirs are available, mainly due to the high clay content which results in significant adsorption of surfactants . Also, carbonate reservoirs are complex and heterogeneous and cEOR is less effective with carbonates. , Precipitation of calcium carbonate and calcium hydroxide occurs as a result of the reaction of injected surfactants with divalent ions, particularly Ca 2+ and Mg 2+ .…”

“…A recent trend in surfactant EOR is the use of a chelating agent or a sequestration agent together with the surfactant in high-salinity environments to sequester divalent cations . Some commonly used chelating agents are ethylenediaminetetraacetic acid (EDTA), tetrasodium EDTA, and sodium acetate. , Recently acrylic acid has been used in a high-salinity environment to avoid precipitation . The acrylic acid reacts with sodium ions and forms the precipitation inhibitor sodium acrylate, which reacts with mineral divalent ions and prevents the formation of precipitates .…”

Research progress of viscoelastic surfactants for enhanced oil recovery

“…react with Ca 2þ and Mg 2þ or ion exchange with clay, act as a sacrificial agent, protect polymers and surfactants. References: (Dang et al, 2018;Demin et al, 1999;Gbadamosi et al, 2019;Guo et al, 2017a;Hou et al, 2005;Kalwar et al, 2014;Mandal, 2015;Olajire, 2014;Pal et al, 2018a;Sheng, 2014) (Demirbas et al, 2015;Gbadamosi et al, 2019;Gong et al, 2016;Kamal et al, 2017;Mandal, 2015;Pei et al, 2013;Sheng, 2013aSheng, , 2013bSorbie, 2013;Wang et al, 2011Wang et al, , 2013Xiaoqin et al, 2013;Xin et al, 2018).…”