Online Journal for E&P Geoscientists

Al-Aisri, Zayana M.^*1; Dieckmann, Volker ²; Tegelaar, Erik ²; Ghammari, Mohd ¹; Gomez Perez, Irene ¹; Farqani, Sulaiman ¹; Peters, Henning ²; Claps, Michele ¹
(1) Exploration, Petroleum Development Oman, Muscat, Oman. (2) Shell International Exploration and Production, Rijswijk, Netherlands.

Hydrogen Sulphide (H2S) is a well known contaminant in hydrocarbon accumulations especially in deep carbonate reservoirs. Understanding its nature and behaviour is crucial to predict concentration variations during field full life cycle.

This paper presents the results of an integrated study aimed to understand the occurrence of H2S in an oil and gas accumulation within a Permo-Triassic carbonate reservoir in a North Oman field, in order to contribute to its Field Development Plan. The reservoir is currently buried to 2.7 km and is at temperatures of around 110°C. Since initial H2S content from test results varied approximately from 1 to 4%, this study was initiated to improve the understanding of H2S origin and distribution in the reservoir.

An integrated approach was undertaken in the study. The hydrocarbon generation and migration model was assessed using both molecular and carbon isotope data for oils, condensates and gas samples from several wells in the field. H2S formation mechanisms were constrained using sulphur isotope data for H2S, condensate, and reservoir minerals (pyrite and anhydrite). Detailed analyses of the polar fraction of the oils by comprehensive 2-dimensional gas chromatography-mass spectrometry were used to further verify the formation mechanisms of H2S. The diagenetic products and the paragenetic sequence were constrained from mineralogy (Qemscan) and detailed transmitted and cathodoluminescence microscopy, as well as stable isotopes (C, O, Sr) and fluid inclusions analyses.

The results suggest that the observed H2S is mainly a product of Bacterial Sulphate Reduction (BSR). Evidence of biodegradation is from molecular compounds and the presence of early bitumen, at temperatures between 60-85° C. On the other hand, incipient Thermochemical Sulphate Reduction (TSR) could not be completely ruled out. Low concentrations of thiadiamentanes and some high homogenization temperatures recorded from fluid inclusions suggest that the reservoir hydrocarbons experienced incipient stages or incomplete TSR in late diagenetic stages. BSR is not occurring at present as the present reservoir temperatures (110°C) is too high. In addition, temperatures may be too low for TSR to progress.

The current understanding of the H2S process and its behaviour is narrowing down one of our key subsurface uncertainty, thereby constraining our development and well and reservoir management options.