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AAPG Bulletin

Abstract

AAPG Bulletin, V. 91, No. 4 (April 2007), P. 535-549.

Copyright copy2007. The American Association of Petroleum Geologists. All rights reserved.

DOI:10.1306/10270606060

Thermal maturity of the Barnett Shale determined from well-log analysis

Hank Zhao,1 Natalie B. Givens,2 Brad Curtis3

13906 Dunwich Drive, Richardson, Texas 75082; [email protected]
2EnCana Oil amp Gas (USA), Dallas, Texas 75240; [email protected]
3Republic Energy Inc., Dallas, Texas 75206; [email protected]

ABSTRACT

Intensive development with large-scale fracturing treatments has made the Barnett Shale play (Newark East field) in the Fort Worth Basin the largest shale-gas field in the world. The Mississippian Barnett Shale is an organic-rich, self-sourced reservoir rock. Thermal maturity, thickness, and total organic carbon are the most important geological factors for commercial gas production from this shale formation. The log-derived thermal-maturity index (MI) has been developed in an effort to better understand and predict hydrocarbon phases across the basin. Maturity index was calculated using three types of open-hole logs: neutron porosity, deep resistivity, and density porosity (or bulk density). The derivation of MI is based on the hypotheses that shale gas is generated and stored locally without apparent migration from outside sources, and that the water saturation and the density of generated hydrocarbons decrease with an increase in thermal maturity. Maturity index correlates well with initial gas:oil ratios (GOR) from well production data. Based on this correlation, an empirical relationship has been demonstrated for the Fort Worth Basin. This method is useful in understanding the thermal-maturity levels of Barnett Shale source rock in the gas-generation window. Mapping MI, GOR, and gas heating value from hundreds of wells identifies the various maturity stages and areas of Barnett Shale that generate oil, condensate, wet gas, or dry gas in the Fort Worth Basin.

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