Reservoir Souring in the Caroline Field

Abstract

Abstract This paper presents a novel mechanism for reservoir souring which is based on the evolution of acid gas from sour aqueous phases present in the reservoir. Souring is a widespread phenomenon in seawater floods. The accepted mechanism in these cases is biogenic activity of sulfate reducing bacteria (SRB). Field data from the Caroline reservoir indicate that it is souring. What is intriguing about this field is that it is being developed via conventional blowdown depletion, which suggests that SRB is not the cause. The mechanism presented is based on the physical principles of Henry's Law, which govern the solubility of hydrogen sulfide (H2S) in water. Through material balance analysis and reservoir simulation, the Caroline field is presented as a case study where this mechanism is plausible. Reservoir simulation which account for this phenomenon was subsequently used to generate more realistic gas composition, thus optimizing the operations of the $1 billion Caroline facility. Introduction Reservoir souring is a term which generally applies to any process which increases the H2S concentration in a reservoir. In this paper, reservoir souring refers to the increase of H2S concentration in the produced fluid. H2S is reactive and highly toxic; increasing amounts of it pose serious health, safety and environmental concerns. Detrimental souring effects include increased corrosion rates of iron and steel, precipitation of ferrous sulfide and contamination of produced fluids. Due to these concerns, reservoir souring can result in significant costs associated with replacement of downhole and surface equipment and increased refining costs due to higher sulfur content of produced hydrocarbons, potentially resulting in early abandonment of the reservoir. From the start of its seven-year production history, the Caroline field has experienced increases in H2S concentration (1–4 mole %). The souring experienced in Caroline differs from that experienced in other fields in that this is a gas condensate reservoir being developed via conventional blowdown. Moreover, the produced fluids are already quite sour (33–39 mole % H2S at discovery). The proposed mechanism for reservoir souring is based on the fact that H2S is more soluble in water than hydrocarbons are (at 36.5 MPa and 106°C: solubility of H2S = 32.8 g/L, solubility of CH4 = 1.2 g/L). As the reservoir pressure is depleted through production, acid gas is liberated from the aqueous phases, be they regional aquifers or connate water, in order to re-establish equilibrium between gaseous and aqueous phases of the reservoir. The purpose of this paper is to demonstrate that acid gas liberation from aqueous phases within the reservoir is a potential mechanism for reservoir souring. Shell Canada's Caroline field is provided as a case study where this mechanism could occur. Caroline Reservoir. The Caroline field is located approximately 150 km north of Calgary, in the province of Alberta. Discovered in 1986, and on full scale production since 1993, Caroline is the largest discovery of its kind in the Western Canadian Sedimentary Basin in the past 30 years.1 It is a sour, retrograde condensate reservoir containing 56 BCM of gas initially in place (GIIP). Average reservoir properties are presented in Table 1. The Caroline reservoir is a highly dolomitized, reefal carbonate complex producing from the Swan Hills member of the Devonian Beaverhill Lake formation, located at a depth of approximately 3500 m. The reservoir has a northwest strike and southwest dip of approximately 25 m/km. Gas is stratigraphically trapped updip by the shales and argillaceous limestones of the Waterways Formation (forming the top seal) and the limestone, siltstones and shales of the Calumet and Elk Point Formations (comprising the bottom seal). Caroline Reservoir. The Caroline field is located approximately 150 km north of Calgary, in the province of Alberta. Discovered in 1986, and on full scale production since 1993, Caroline is the largest discovery of its kind in the Western Canadian Sedimentary Basin in the past 30 years.1 It is a sour, retrograde condensate reservoir containing 56 BCM of gas initially in place (GIIP). Average reservoir properties are presented in Table 1. The Caroline reservoir is a highly dolomitized, reefal carbonate complex producing from the Swan Hills member of the Devonian Beaverhill Lake formation, located at a depth of approximately 3500 m. The reservoir has a northwest strike and southwest dip of approximately 25 m/km. Gas is stratigraphically trapped updip by the shales and argillaceous limestones of the Waterways Formation (forming the top seal) and the limestone, siltstones and shales of the Calumet and Elk Point Formations (comprising the bottom seal).