Quantifying Geochemical Interactions When Injecting into a Sour Oil or Gas Field

Abstract

In this paper the study results for gas and/or water injection into sour fields located in the South Oman Salt Basin (SOSB) is presented. The hydrocarbons in the fields are contained in carbonate "stringer" reservoirs, which are slabs of carbonates floating within salt. The fields in this area are typically high pressure, high temperature sour (H2S and CO2) reservoirs.The typical development concept for these type of fields in general follows a staged approach: (1) An appraisal phase, (2) An early production phase from primary depletion, followed by (3) a miscible gas flood (or a water flood), and ultimately (4) a gas blow down phase. The objective of this phasing is to allow for optimal learning and economies of scale. This paper presents a part of the work done in preparation of the third development phase with a specific focus on quantifying the interaction of an injectant with the reservoir rock. In other words due to geochemical reactions of the injected gas (or water) with the host rock or formation water, mineral dissolution or precipitation can occur. As a result, the reservoir properties in the reservoir are altered that could potentially result in well injectivity and/or productivity issues (either through pore plugging or fine migration).The development of reactive flow simulation tools that are capable of modeling the relevant process (e.g. fluid flow, geochemistry, rock behavior) is currently an active research topic in industry. In this paper we will present a modeling workflow to improve our fundamental understanding taking into account some of the current limitations of the modeling tools. The workflow will be described through presenting several modeling examples using different simulation tools (e.g. geochemical modeling tools, PVT modeling tools).