Abstract Conventional methods of rock typing based on porosity-permeability cross-plots do not work in shales due to lack of dynamic range and difficulties involved in the direct measurements of most of the petrophysical parameters.. Here we present a methodology for rock typing in Barnett shale by integrating geological core description with porosity, total organic carbon (TOC), mineralogy and mercury injection capillary pressure which are relatively easy to measure. Petrophysical measurements were made on 800 plugs obtained from almost 1600 feet of core recovered from four wells from Newark East field, TX. Lithofacies of all the plugs were assigned using the stratigraphic columns developed by Singh (2008). From the petrophysical measurements, we observe three such groups or rock types. The three rock types so formed are termed as petrofacies ‘1’, ‘2’ and ‘3’. Each petrofacies was found to have distinct capillary pressure curve, and microstructure determined by ESEM. Cluster analysis of the petrophysica data set also indicates that rocks can be grouped into three clusters. Petrofacies 1 represents the best reservoir rock with high porosity, TOC and quartz content and low calcite content whereas petrofacies 3 represents the worst reservoir rock with high calcite content and low porosity and TOC. In order to verify that petrofacies 1 is indeed the best reservoir rock; we compared the thickness of the petrofacies with the overall gas production in two vertical wells. It is observed that the well with most continuous intervals of petrofacies 1, with minimum interference of petrofacies 2 and 3 over the perforated zone, produces better than the well with thick intervals of petrofacies 2 and 3 frequently separating petrofacies 1. This confirms that petrofacies 1 which is the best reservoir rock in a petrophysical sense is also a better gas producer.