Advances in the Prediction and Management of Elemental Sulfur Deposition Associated with Sour Gas Production from Fractured Carbonate Reservoirs

Abstract

Abstract Shell Canada has experienced significant deposition of solid sulfur during the production of dry sour gas from several of its deep carbonate pools located in Southern Alberta. In several cases, wells have become completely plugged with sulfur in the reservoir within several months. Accurate prediction and effective management of the sulfur deposition are crucial to the economic viability of these fields. A new analytical model has been developed for predicting sulfur deposition associated with sour gas production in naturally fractured reservoirs. Key features of the model include incorporation of reservoir temperature profiles and the concept of critical velocity, which accounts for dynamic effects, resulting in a zone of reduced deposition close to the wellbore. The model has been used to successfully match and predict sulfur deposition in several sour gas producers. The modeling results have been used as a design basis for downhole sulfur treatments and clean-out operations, the optimization of well completions and off-take rates to minimize the impact of sulfur deposition, and the development of new well designs and operating strategies for sulfur producers. Introduction Elemental sulfur is present as a dissolved species in virtually all deep sour gas reservoirs. Sulfur precipitation is induced by a reduction in the solubility of the sulfur in the gas phase beyond its thermodynamic saturation point as a result of decreases in pressure and temperature. These changes occur during production operations and can result in sulfur deposition in the reservoir, wellbore and surface facilities1. Shell Canada has experienced significant deposition of solid sulfur during the production of dry, sour (15–30% H2S) gas from several of its deep (3000–4000 m [10,000–13,000 ft]) carbonate pools (30–40 MPa [4500–5750 psi], 80–100 °C [175–215 °F]) located in the Foothills of the Canadian Rockies in Southern Alberta, Canada1. Despite sulfur content determinations typically not exceeding 2 g/scm [125 lb/MMscf], in several cases, wells flowing at relatively low rates, 150–300 103m3/d [5–10 MMscf/d], have become completely plugged with sulfur in the reservoir within several months. Accurate prediction and effective management of the sulfur deposition are critical to the economic viability of these fields. Many investigations relating to sulfur deposition have been reported. Whilst most papers focus on the wellbore and use of sulfur solvents, several papers do discuss techniques for predicting and managing reservoir plugging1–5. However, not all of these studies are relevant to solid sulfur deposition associated with sour gas production. Furthermore, some of the key results and conclusions from the relevant papers are not supported by Shell Canada's most recent field experience. Against this background and building on the approach of the earlier work, new analytical models have been developed for predicting sulfur deposition associated with dry, sour gas production. The basic model is a production system tool for predicting the quantity and location of sulfur deposition in the reservoir, wellbore and at surface (production system model). The other models are more complex and can be used to predict sulfur deposition in naturally fractured reservoirs (fracture model) and non-naturally fractured, or mechanically fractured reservoirs (matrix model). This paper describes the development and key advances of the new analytical fracture model, and assesses the implications of the results for managing sulfur deposition in naturally fractured reservoirs.