Predicting Fluid Quality from Regional Thermal Maturity Studies
The ability to predict fluid quality prior to production from tight oil and gas plays can be necessary to determine the economic viability of a play. There are many tools available to the explorationist to determine the maturity of rocks, oils and gases. The stable isotopic composition of natural gas is useful in the interpretation of gas type (i.e., bacterial versus thermal origin), hydrocarbon maturity, migration and reservoir compartmentalization. With a properly developed regional calibration, stable isotope data can be used as a reliable indicator of oil-associated gas maturity. By comparing rock and gas maturity data, we can also estimate if reservoir hydrocarbons migrated or accumulated in-situ. If a tight oil and gas play can be classified as a petroleum system with low to no migration, determination of the maturity of the fluid itself can lead to a robust fluid maturity predictor. Gases associated with liquids production are often collected prior to completion operations in tight oil and gas plays. Mud gases can be collected while drilling, desorbing gases from collected cuttings or core rock, and production oils and gases from nearby wells can be analyzed and interpreted for fluid maturity. The framework utility of regional basin modeling is to establish a rock maturity baseline. The derived oil and gas maturity can be quickly compared to the rock maturity to delineate migration in a play. Correlation of carbon and hydrogen isotope maturity from methane, ethane, and propane to gas to oil ratio and condensate yield is established. A regional dataset such as the one presented here allows for the creation of a regional maturity map which can be an invaluable tool in identifying dry gas, wet gas, retrograde gas, volatile oil and black oil associated areas of an unconventional resource play.
AAPG Datapages/Search and Discovery Article #90193 © 2014 Rocky Mountain Section AAPG Annual Meeting, Denver, Colorado, July 20-22, 2014