Fang Hao,² Sitian Li,² Zaisheng Gong,³ and Jiaming Yang³

©Copyright 2000. The American Association of Petroleum Geologists. All rights reserved.
¹Manuscript received October 19, 1998; revised manuscript received September 21, 1999; final acceptance November 15, 1999.
²Department of Petroleum Geology, China University of Geosciences, Wuhan 430074, Hubei, People’s Republic of China; e-mail: [email protected]
³China National Offshore Oil Corporation, Beijing, People’s Republic of China.
This project was supported by China National Natural Science Foundation (No. 49732005) and 973 Project G1999043309. We appreciate collaboration with and enthusiastic support from Qiming Zhang, Shixiang Cai, Zhongliang Hu, Baojia Huang, Xianzhuang Pan, and many other co-workers in the Institute of Petroleum Exploration and Development, Nanhai West Oil Corporation. We thank Richard M. Pollastro (U.S. Geological Survey) for helpful discussions. Jean K. Whelan (Woods Hole Oceanographic Institution), John B. Curtis (Colorado School of Mines), Paul Lillis, and Richard Pollastro (U.S. Geological Survey) are gratefully acknowledged for their constructive reviews of an earlier version of this manuscript, which greatly improved this manuscript. This manuscript significantly benefited in clarity and quality from critical reviews by Neil Hurley, W. A. England, Kenneth Wolgemuth, and two anonymous AAPG Bulletin reviewers.

ABSTRACT

The Dongfang gas field, located in a diapir structure zone, is the largest gas field found in the Yinggehai Basin. A strong thermal anomaly caused by hydrothermal fluid flows occurs in the gas field, as evidenced from drill-stem test and fluid inclusion homogenization temperatures, Rock-Eval T_max, vitrinite reflectance, and clay-mineral transformation profiles. Such a thermal anomaly suggests focused, rapid flow of deeply sourced hydrothermal fluids, which has shifted the threshold depth to the onset of hydrocarbon generation upward by about 500 m. The Dongfang gas field shows considerable variation in nitrogen and carbon dioxide content, with nitrogen content ranging from less than 5 to 31.2% and carbon dioxide content ranging from less than 1 to 88.9%. Hydrocarbon gases and associated condensates show high maturities and have been generated most probably from the Meishan and Sanya formations of Miocene age. Carbon dioxide in gases with CO₂ content less than 10% is organic in origin, whereas carbon dioxide in gases with CO₂ content higher than 10% is inorganic in origin and has been generated from high-temperature decomposition of carbonates. Most gases display negative d¹⁵N values. Gases with nitrogen content higher than 15% always contain organic CO₂ (CO₂d¹³C values lighter than -10o/oo,), and the nitrogen contents decrease as the d¹³C values for methane and ethane become heavier, suggesting an organic origin of the nitrogen gas generated in the catagenetic stage (source rock R_o <2.0%), before the significant thermal decomposition of carbonate took place. Systematic interreservoir compositional heterogeneities occur in the gas field, which, along with the thermal regime and fluid-inclusion homogenization-temperature measurements, give a clear suggestion of the reservoir-filling history: methane-dominated gases with relatively high nitrogen content and a small amount of organic CO₂ accumulated first, and carbon dioxide-rich gases with hydrocarbon components of higher maturity injected into the reservoir later. Interreservoir compositional heterogeneities, which have the advantage of being unaffected by in-reservoir mixing processes, can be effective indicators of the field-filling history, especially when they are studied in combination with fluid-inclusion and reservoir-diagenesis analyses. The short-lived, transient nature of the thermal effect of fluid flow and the wide variation of the toluene/n-heptane values seem to suggest episodic fluid injections from the overpressured systems into the reservoirs.