American Journal of Chemical Engineering 2017; 5(3-1): 1-9 http://www.sciencepublishinggroup.com/j/ajche doi: 10.11648/j.ajche.s.2017050301.11 ISSN: 2330-8605 (Print); ISSN: 2330-8613 (Online) Potential of a Locally Made ASP Formulation Ogbonor (Irvingia Gabonensis) in Enhanced Oil Recovery Processes Koyejo Oduola, Nyemachi Oriji Department of Chemical Engineering, University of Port Harcourt, Port Harcourt, Nigeria Email address: koyejo.oduola@uniport.edu.ng (K. Oduola) To cite this article: Koyejo Oduola, Nyemachi Oriji. Potential of a Locally Made ASP Formulation Ogbonor (Irvingia Gabonensis) in Enhanced Oil Recovery Processes. American Journal of Chemical Engineering. Special Issue: Oil Field Chemicals and Petrochemicals. Vol. 5, No. 3-1, 2017, pp. 1-9. doi: 10.11648/j.ajche.s.2017050301.11 Received: March 29, 2017; Accepted: March 30, 2017; Published: April 11, 2017 Abstract: The quest for techniques to recover the remaining 60–80% of the original oil in place (OOIP) left upon conventional oil recovery methods has become imperative. Alkaline–surfactant–polymer (ASP) flooding has emerged as one of the most promising and widely applicable techniques due to its significant improvement on the displacement and sweep efficiency. A number of the attempts has been devoted to investigating the combination of up to three substances to form the appropriate ASP system for a given application, which has been without a number of technical challenges. This paper reviews the possibility of employing an appropriately engineered synthesis of an ASP substance which incorporates all the three components in one. Research has been conducted into the suitability of an ASP system formulated using locally available and thus economically viable raw materials (Ogbonor seeds, Irvingia gabonensis, potash, and salt). The study shows the best level of salinity needed for the retention of the polymer gel viscosity is 30g/l and the maximum viscosity of the polymer solution is 1.086, in the absence of additives. This brought to a conclusion that the chosen additive (potash) does not have a significant effect on the polymer solution that will result in highest viscosity which enhances a good percentage of oil recovery. Polynomial models relating the resulting polymer viscosity with concentration and salinity have been developed, applicable for predicting polymer viscosity at different concentrations of salt and additive. Keywords: Alkaline, Surfactant, Polymer, Oil Recovery, Viscosity, Ogbonor, Salinity, Modeling 1. Introduction Alkaline–surfactant–polymer (ASP) is a combination process in which alkali, surfactant, and polymer are injected in the same slug which outrightly affects oil flow behavior in the reservoir. Because of the synergy of these three components, ASP offers a considerable potential in chemical enhanced oil recovery (EOR). The success of this process depends on the proper combination of alkali, surfactant, and polymer and their compatibility with a reservoir. In the ASP process, Chemicals used are an alkali (NaOH or Na 2 CO 3 ), a surfactant and a polymer. Surfactants are chemicals used for the reduction of interfacial tension between the involved fluids, making the immobile oil mobile. Alkali reduces adsorption of the surfactant on the rock surfaces and reacts with acids in the oil to create natural surfactant. Polymer improves the sweep efficiency. ASP in a system gives rise to, oil mobililty, diminishing of interfacial tension, and increase in sweep. The process can also change the pH of the system depending on surfactant introduced and the alkali concentration [1]. The ASP method can be applied as an improved waterflooding with large slug of low surfactant concentration. The objective of the ASP flooding process is to reduce the amount of chemical consumed per unit volume of oil required and invariable a reduction in cost. ASP floods in the world were commercially successful and were seen as an important technology for EOR; however, the projects were generally small. Difficulties in applying large reservoir scale surfactant flooding are due to the evaluation of potential recoveries mainly because reservoir modeling is not available yet. The production rates of the 100 largest oilfields in the world are all declining from plateau production. The challenge is to develop EOR methods that ensure an economical tail end production from these fields. Field practice has shown that more than 20% OOIP incremental recoveries can be obtained with the ASP process. Better ASP