A Non-Conventional Study for Determination of H2S in Production Gas

Abstract By mid-2000, the H2S content in gas from the Chihuido Lomitas field separator started to increase significantly up to an average of 2,000 ppm. A multidisciplinary team was formed to address the problem, which was deemed to be very likely due to bacterial activity in the reservoir. Therefore, the group focused on the issue of concern, which is generally known as reservoir souring. It was concluded that using sulphur isotope measurement techniques was one of the few tools available to effectively determine the cause of the souring. A group of specialists in isotope assessments from a local Research Institute was called in to join the team. Based on the team's findings, supported by a geochemical model, it was shown that H2S generation in the Troncoso and Avile formations was due to the activity of sulphate reducing bacteria living in the reservoir. The model developed relates increasing bleeding water injection to the phenomenon studied. A thermo-chemical reduction was proposed to explain the H2S content in El Filon Reservoir. Innovative H2S removal techniques are currently being applied. Introduction The Chihuido Lomitas light oil field is located in the Neuquen Basin, in Argentina. The main producer reservoirs (Agrio Formation and Avile Member) are in the Mendoza Group (Late Jurassic - Early Cretaceous). One non-conventional reservoir produces from an igneous rock (see Figure 1). The field started to produce in the early 1980s, and is currently Repsol YPF's main oil field in Latin America. Water injection started in 1996 and, by the end of 2001, nearly 100,000 m3/day were injected through 480 injection wells. Initially, just fresh water was injected, but it was gradually replaced by production water. When the H2S content in the separator gas started to increase, a team was formed including field staff from Engineering and researchers from Repsol-YPF's Applied Technology Centre (CTA) in order to address the problem by looking at different approaches. Measurements were thoroughly checked, and a sampling survey at key points was designed. Different gas treating alternatives were discussed. It was concluded that sulphur isotope measurement techniques were one of the few tools available to effectively determine the origin of the problem. Sampling H2S collection was accomplished with a sampling device developed at INGEIS, including a flow meter and two H2S traps, with two online flasks containing AgNO3 or NaOH. Sixty samples were taken from all batteries, including formation, production, and injection water, oxygen scavengers, and crude oil. Isotope analyses were performed at INGEIS using VG 602 and Finnigan Delta-S mass spectrometers. CTA performed a standard geochemical analysis, and determined the level of fatty acids in the formation waters. Results and Discussion The main data are shown in Tables 1 and 2. We carefully analysed the different possibilities for H2S generation in the reservoir, on the basis of the isotopes results, geology, temperature range, presence of sulphides in reservoir formations, and injection/production water characteristics. The analysis also took into account the exploitation history, and the absence of H2S in the early years.