Gas-liquid-solid Coupled Flow Modelling in Fractured Carbonate Gas Reservoir with high H2S-content

Du, Zhimin (The State Key Laboratory of Oil and Gas Reservoir Geology and Exploitation) | Guo, Xiao (The State Key Laboratory of Oil and Gas Reservoir Geology and Exploitation) | Zhang, Yong (Southwest Petroleum University) | Yang, Feng (Southwest Petroleum University) | Shan, Gaojin (Southwest Petroleum University) | Wu, Yong

OnePetro 

Abstract

Technical studies, production and operations, and management of fractured carbonate gas reservoir with high H2S-content are difficult and uneconomical tasks to perform due to high toxicity and corrosivity of H2S. The optimization of conceptual design of these reservoirs may become cost efficient through the use of integrated simulation. However, to our knowledge, previous models do not well allow for the characteristics of complex flow through porous media in fractured carbonate gas reservoir with high H2S-content, nor do they consider the influence of the special physical and chemical changes on production performance, which makes the prediction of production behavior uncertain. In this paper, mechanisms of the gas-liquid-solid migration and formation damage resulting from sulfur deposition in fractured carbonate gas reservoir with high H2S-content were investigated by means of numerical simulation. A new gas-liquid-solid coupling model in fractured carbonate gas reservoir with high H2S-content, accounting for sulfur deposition, phase behavior variation, geochemical rock-water-gas interactions, adsorption, was presented. A modified equation of state was also used to describe phase behavior variation and combined with the integrated model. The model can forecast the production mechanisms and performance of fractured carbonate gas reservoir with high H2S-content, particularly, evaluate accurately and rapidly H2S concentration, mole content spatial distribution and dynamic change with pressure or time. This work can also promote safer development design to fractured carbonate gas reservoir with high H2S-content and avoid failure in operations.

Introduction

In South China, many carbonate gas reservoirs suffer of having large of hydrogen sulfide and other sulfur compounds. Technical studies, production and operations, and management of this type of carbonate gas reservoirs with high H2S-content are difficult and uneconomical tasks to perform due to high toxicity and corrosivity of H2S[1]Reduction in pressure and temperature also induced sulfur precipitation by a reduction in the solubility of the sulfur in the gas phase beyond its thermodynamic saturation point. These changes occur during production operations and can result in sulfur deposition in the reservoir, wellbore and surface facilities. Deposition of elemental sulfur in the near well bore area and within reservoir rocks may significantly reduce the inflow performance of gas wells. Thus, the optimization of conceptual design of these reservoirs may become cost efficient and difficult.

An early recognition of many problems due to sulfur deposition associated with the production of sour gas has been achieved. Kuo and Colsmann[2]developed the first mathematical model of a solid phase precipitation in porous medium and its influence on fluid flow. The model considered elemental sulfur as some of dissolved sulfur precipitates from the solution as a result of depletion of reservoir pressure. The results of the study showed a rapid buildup of solid sulfur around the well and significant deposition near the outer boundary of the reservoir. Hyne[3] presented a survey of more than 100 producing wells in Canada and Europe about field operations of sour gas production. The survey focused on sulfur deposition at the bottom of producing wells and showed that high bottom hole and wellhead temperatures and low wellhead pressures provide favorable conditions for sulfur deposition in well tubing. Al-Awadhy et al[4] performed the first study to investigate sulfur deposition in carbonate oil reservoirs. They conducted a single experiment and developed a numerical model describing the phenomena. Shedid and Zekri [5] conducted a detailed experimental study using a wide range of applied flow rates, different initial concentrations of sulfur and different rock permeability. The results of the study stressed the severity of the problem associated with sulfur deposition for different flow rates and under different initial sulfur concentrations of the crude oil. Shedid et al[6] carried out ten dynamic flow experiments using different crude oils of different sulfur and asphaltene concentrations and under different flow rates to investigate the simultaneous deposition of sulfur and asphaltene in porous media. The results of this study indicated the increase of simultaneous sulfur and asphaltene concentrations in the flowing oil increases and accelerates the permeability damage affects in carbonate reservoirs.