Advances in Reservoir Quality Assessment of Tight-Gas Sands - Links to Producibility

Robert Klimentidis and Joann Welton
New Play Concepts, ExxonMobil Research, Houston, TX

The two main types of porosity generally found in sandstones are: primary intergranular observed between detrital grains, characteristic of conventional reservoirs, and secondary porosity encountered in partially dissolved detrital grains, microporous detrital grains, rock fragments, detrital clay matrix, and various diagenetic mineral cements such as clay minerals (chlorite, kaolinite, illite/smectite, illite, etc.), micro-crystalline carbonate, etc. Secondary porosity is the pore type found commonly in low quality, tight sandstones more typical of tight-gas reservoirs. Differentiation and quantification of the various porosity types is an essential step in understanding and predicting the producibility of tight-gas reservoirs and types of completions/stimulations which may be required.

A typical tight sandstone (i.e. a reservoir which requires artificial stimulation to produce at economic rates) is characterized by a wide range of pore-throat sizes which in turn controls such parameters as permeability, water saturation, producible pore volume and producibility potential (e.g. hydrocarbon flow rates and cumulative production). The ability to characterize and quantify pore types based on mineralogical trends in a stratigraphic framework within a basin allows one to build a predictive reservoir quality spatial model. This model can assist in locating better reservoir quality intervals (“sweet-spots”) and in the design of optimal completion/stimulation protocols.

AAPG Search and Discover Article #90078©2008 AAPG Annual Convention, San Antonio, Texas