Induced H2S formation during steam injection recovery process of heavy oil from the Liaohe Basin, NE China

H2S is generally very low in fresh water lacustrine origin oil and gas deposits, while unusual high amounts of H2S in thermal recovery pilot areas may be formed in situ during steam injection process. Present paper shows such kind of case study from the Liaohe Basin, NE China, where abundant heavy oil accumulated in the Eogene sandstone reservoirs with burial depth shallower than 1000m. Qi 40 Block is one of pilot areas where steam injection was applied for heavy oil recovery. Almost no H2S can be detected in initial gas production, while up to 3% of H2S occurs in associated gas after thermal recovery. We proposed that most of H2S were derived from the TSR (thermochemical sulfate reduction) during thermal recovery, even though minor amount of H2S from thermal decomposition of organosulfur compound (TDS) within oil cannot be ruled out. Heavy oils in the Liaohe Basin contain very low amount of sulfur (generally <0.3%), which cannot generate decent amount of H2S during thermal decomposition of heavy oil. However, the formation water in Eogene Shahejie Formation is rich in sulfate ions (SO42−), which can provide reactant for TSR reaction triggered by thermal stress from injected steam. Geochemical data including sulfur isotope of H2S, oil, sulfate, and natural gas, support the conclusion that the abundant H2S from the steam drive pilots of the Liaohe Basin are mainly originated from TSR effect under high temperature during the thermal recovery process. The observed δ34S variations lend support to the conclusion that in situ thermochemical sulfate reduction can occur during thermal recovery process. The intensity of TSR and amount of H2S occurring in pilot areas is controlled by methods of steam injection, temperature and times of treatment.