H2S artificial formation as a result of steam injection for EOR: a compositional kinetic approach.

Abstract

Abstract As a result of hydrothermal stress induced by steam injection in reservoirs, heavy crudes undergo chemical transformations, called aquathermolysis, the extent of which depends at least on steam temperature, injection history and both crude and mineral matrix physicochemical properties. As heavy crudes often have high sulfur content, their hydrothermal alteration results in the formation of H2S. In order to predict artificial H2S emissions during thermal EOR, we seek to develop a geochemical model to be coupled with a 3D reservoir simulator. This paper presents the first step of the process that consists in simulating in-situ aquathermoysis in laboratory in order to derive a 0D compositional kinetic model for H2S formation. For that purpose, aquathermolysis experiments were performed on an Athabasca oil sand sample. The amount of H2S generated during aquathermolysis was measured for different time and temperature conditions. At the same time, sulfur distribution was quantified over crude SARA fractions (Saturates, Aromatics, Resins and Asphaltenes) and insoluble fraction (mainly mineral), before and after aquathermolysis. Experimental results were then derived to elaborate a kinetic model of H2S generation upon aquathermolysis, encompassing the chemical conversion of sulfur in SARA and insoluble fractions. Introduction Steam and hot water assisted recovery from heavy oil reservoirs can induce physicochemical interactions between water, oil and rock. As a result, significant amounts of hydrogen sulfide, together with carbon dioxide, may be generated, increasing the risk of corrosion, health security problems and environmental aggression during production (Burger et al., 1985; Mohammed et al., 1990; Thimm, 2001). Aquathermolysis is defined as the sum chemical reactions between heavy oil and steam (Hyne et al., 1984; Hoffman et al., 1995). Aquathermolysis laboratory experiments were previously carried out, either on isolated heavy crude (Hyne and Clark, 1981), or on whole core samples (Akstinat, 1983; Hyne et al., 1984; Attar et al., 1984; Monin and Audibert, 1988; Hoffman and Steinfatt, 1993; Belgrave et al., 1994; Pahlavan and Rafiqul, 1995). These studies emphasized the importance of aquathermolysis as a source of H2S during steam and hot water injection. This process may be quite efficient for temperatures higher than 200°C at production time scale. Moreover, H2S yields and formation rates appeared to depend merely upon the amount and the nature of organic sulfur compounds in heavy oil (Hyne et al., 1984; Attar et al., 1984; Lamoureux-Var and Lorant, 2005). This latter observation suggests that, as a first approximation, the H2S potential of a reservoir rock submitted to steam injection might be correlated to the content of the most hydrothermally labile sulfur compounds in the reservoir. Assuming these compounds might be contained in specific fractions of the oil sand, the aim of this work was:to assess which fraction(s) of the oil sand (SARA + insoluble) might be the source(s) of H2S;from this assessment, to correlate H2S generation to sulfur distribution over the source fractions, via a kinetic formulation.