Fluid evolution in the Permian Maokou Formation in the Tailai Gas Field, eastern Sichuan Basin, China

Abstract

The hydrothermal dolomite in the Middle Permian Maokou Formation is one of the main natural gas producing units in the Sichuan Basin. The development of this hydrothermal dolomite reservoir was controlled by the Emei magmatism, but its fluid evolution history in the Tailai Gas Field is not well understood. To fill this knowledge gap, we investigated the diagenetic sequences of veins, origins of minerals, salinity history and pressure evolution by an integrated examination of Raman spectroscopy, cathodeluminescence, geochemistry, fluid inclusions, and in situ U–Pb dating of the calcite and dolomite veins. The results show two stages of dolomite veins, three stages of calcite veins and two stages of quartz veins in the hydrothermal dolomite reservoirs. In situ U–Pb dating gave an age range of 264–251 Ma for the two stages of dolomite veins, and 246.9 − 245.3 Ma, 222.4 Ma, and 175.4 Ma, respectively, for the three stages of calcite veins. Fluid inclusion studies showed that the first and second stage of quartz veins were formed in around 173 Ma and 150 Ma, respectively. The 87Sr/86Sr, δ13C, δ18O and Rare Earth Elements and Yttrium data suggest that the two stages of dolomite veins originated from the pore fluids released from the Ordovician and Cambrian carbonate rocks, and the three stages of calcite veins were sourced from surrounding host rocks, pore fluids released from the Silurian shales, and hydrothermal fluids, respectively. Integrating these data with fluid inclusion data, the salinity evolution of pore fluid in the P2m3 hydrothermal dolomite reservoirs can be summarized into three stages, i.e., an increase from 8.55 wt% to 19.37 wt% NaCl equivalent from 260 to 240 Ma, followed by a decrease to 1.74 wt% NaCl equivalent from 240 Ma to 170 Ma, and remaining at low level (<7.45 wt% NaCl equivalent) from 170 Ma to 100 Ma. The reservoir fluid pressure evolution can also be summarized into three stages: (1) overpressure was generated with the pressure coefficient increasing from 1.00 to 2.14 from 260 to 222 Ma due to gas charge; (2) the overpressure rapidly increased with the pressure coefficient increasing from 2.14 to 2.41 from 222 Ma to 110 Ma owing to crude oil cracking; (3) the reservoir fluid pressure coefficients decreased to 1.16 in well TL6 and 1.52 in well TL7 because of tectonic uplift and gas escape, and remained almost constant in well TL601 because of well preservation from 110 Ma to present. The results in this work show that reservoir fluid pressure evolution is significant to identify the gas charge and escape, and can indicate the preservation conditions of reservoirs.