Petrophysical Characterization of Barnett Shale
Authors: Kale Sagar V. , Rai Chandra S. , Sondergeld Carl H. 
Published: February 2010

Conventional methods of rock typing based on porosity-permeability cross-plots do not work in shales due to lack of dynamic range and the difficulties involved in the directet measurements of most of the petrophysical properties. Here, we have attempted rock typing in Barnett shale play by integrating geological core description with the petrophysical parameters such as porosity, total organic carbon (TOC), mineralogy and mercury injection capillary pressure which are relatively easy to measure.

Dataset of petrophysical measurements used for rock typing is acquired by sampling at every 2 feet interval from almost continuous 1600 feet of core recovered from four well in the Newark East Field, Texas. Porosity and mineralogy is measured at every 2 feet. For Hg injection capillary pressure measurement, sampling is done at every 10 feet. TOC measurements and Environmental Scanning Electron Microscope (ESEM) imaging is also carried out on samples from selected depths.

Lithofacies are assigned to all the samples used in this study using the stratigraphic columns developed by Singh (2008). We observed that certain lithofacies contributed very little thickness to the overall stratigraphic column. Based on the petrophysical measurements, we also observed that some lithofacies had similar petrophysical properties. We combined the lithofacies with similar petrophysical properties into groups so that each group is unique in terms of its petrophysical properties and also contributes significant thickness to the stratigraphic column. From the petrophysical measurements, we observe three such groups or rock types. The three rock types so formed are termed as petrofacies and they are labeled as ‘1’, ‘2’ and ‘3’.

Petrofacies 1 represents the calcite lean (&lt;10% wt.) – clay rich rock with high porosity and TOC. It has the highest quartz content as well; making it the most suitable reservoir rock for initiating a hydraulic fracture. Petrofacies 1 represents the best reservoir rock type in a petrophysical sense. Petrofacies 2 represents reservoir rock with moderate calcite content (10 − 25% wt.). It also exhibits high porosity but its TOC content is rather low. Petrofacies 3 represents calcite rich rock (&gt;25% wt.) with low porosity and low TOC. It represents the worst rock in the field and is not expected to contribute much to gas production.

ESEM imaging of the samples from three petrofacies shows that the petrofacies are not only distinct petrophysically, they are also observed to be unique texturally. Samples from each petrofacies also exhibit unique capillary pressure curve.

Comparing the thickness of the petrofacies with the overall gas production in two vertical wells (in the study area), with similar completions over the same time interval, shows that the well with long and 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.