Oil and Gas

Biography

Biography: Mohamed Sanousi Nasr

Abstract

Secondary oil recovery represents a major part of oil production in many local oil fields. It involves injection of a source water to maintain the reservoir pressure. The source water will eventually mixed with formation water as it breakthroughs to production wells. Mixing of incompatible brines leads to precipitation of various types of mineral scaling compounds such as barium sulphate, strontium sulphate, calcium sulphate or calcium carbonate. The precipitation is also the result of pressure drop or temperature change in the reservoir. These formed scales deposit at formation face, production tubing, and subsurface valves. The most effective way to avoiding this scaling problem is by using scale inhibitor that generally fall into one of the four main classes, polyphosphates, phosphate esters, phosphonates and polymers.
The objective of this paper is to investigate the suitability of the injection of fresh water compared with the reinjection of formation water for three carbonate oil reservoirs. Displacement experiments, for actual core samples collected from sandstone from Abutafel oil field in Sirte Basin, Libya, were utilized for permeability measurements using formation water and fresh water and a combination of the two as the displacing fluid. Scale inhibitors of different types were added to both the formation water and the injection water for the prevention of scale formation in either water alone or a combination of both waters. The investigation is done by conducting relative permeabilitires measurements to oil and to water for both waters. The effect of scale inhibitor in the injection water on the relative permeability curves at ambient and reservoir conditions is also investigated.
The chemical composition of the water to be injected is of great importance because of its influence on the scaling tendency of the water and also on its interaction with the reservoir environment. Chemical equilibrium scale prediction methods were used to predict the scaling tendency of the said waters each one to be used alone or when mixed at various ratios. These methods have been completed by experimental tests (bottle testing) at ambient temperature and also at 185 oF reservoir temperature. The experimental results were obtained from carbonate core samples collected from a giant oil reservoir in Sirte basin, Libya. The reservoir was put on water injection since the start of the pressure decline which was the result of excessive oil withdrawal rates.
The compatibility tests of the two waters indicated that the formation water alone has a higher tendency to form calcium carbonate scale than the fresh water at either ambient or reservoir temperature. It was also found that the scaling tendency increases with increasing the percentages of the formation water in the mixture at either temperature. The fractional displacement flow curve for the injection water yielded better results than formation water when both waters were used as the displacing fluid.