STRATIGRAPHIC AND PETROPHYSICAL CONTROLS ON RESERVOIR PAY AND ITS SPATIAL VARIABILITY, WILLIAMS FORK FORMATION, MAMM CREEK FIELD, COLORADO

Abstract

The Upper Cretaceous Williams Fork Formation of the Mesaverde Group within the Piceance Basin of northwestern Colorado is a significant producer of natural gas from low permeability reservoirs (tight-gas sandstones). The Williams Fork Formation consists of six stratigraphic intervals. From base to top, these zones include the Lower Williams Fork Formation including 1) Cameo-Wheeler Coal Zone, 2) Middle Sandstone/South Canyon Coal Zone, 3) Upper Sandstone, and 4) Paonia Shale Member, and the 5) Middle Williams Fork, and 6) Upper Williams Fork. The two lowermost zones of the Lower Williams Fork Formation consist of fluvial sandstones, shales, and laterally extensive coal zones. The upper two zones of the Lower Williams Fork Formation record a transition from lower coastal plain and swamp to coastal plain deposits represented by fewer coals and a higher proportion of fluvial sandstones. From the upper two zones of the Lower Williams Fork Formation to the Middle and Upper Williams Fork, a transition from coastal plain to an alluvial plain setting is reflected by a greater proportion of sandstones.This study combines well-log and 3D seismic data to yield 3D lithology, porosity, permeability, water saturation, bulk volume water, and reservoir pay models to explore the stratigraphic and petrophysical controls on reservoir pay within the Williams Fork Formation in Mamm Creek Field. The data set includes approximately 48 mi2 (125 km2) of 3D seismic data in time and depth domains, core porosity and permeability data from the Last Dance 43C-3-792 well, and 234 wells with digital well-logs including gamma ray, neutron porosity, density porosity, and resistivity logs. Three-dimensional petrophysical property models reveal that Williams Fork Formation sandstones exhibit total and effective porosity ranges of ~5-15% and ~1-8%, respectively, absolute permeability of ~0.7- 10 µD, and bulk volume water of ~0.03-0.06. Core data suggest that matrix permeability is positively correlated with total and effective porosity. Within the study area, 40% of the Williams Fork Formation is composed of thick, laterally extensive reservoir pay sandstones that on average, reflect total porosity ~9-11%, effective porosity ~3-4%, slightly higher permeability ~7-20 µD, water saturation ~50-85% (avg. ~80%), and bulk volume water ~0.01-0.05 (avg. 0.03). While the range and mean values of petrophysical properties do not vary significantly stratigraphically, lithology, reservoir pay, and pore volume are highly variable stratigraphically. The majority of reservoir pay is confined within the lower two-thirds of the Williams Fork Formation (Lower Williams Fork Formation and Middle Williams Fork). Of the two major reservoir pay contributors, the Lower Williams Fork Formation contains the thickest pay sandstones that range in thickness from ~350-550 ft (106-167 m). 3D reservoir models of lithology, effective porosity, and other petrophysical properties illustrate the stratigraphic and petrophysical controls on high reservoir quality sandstones that form natural gas reservoirs. This work demonstrates that the most prospective reservoir intervals occur within the lower two-thirds of the Williams Fork Formation, with optimal reservoir properties concentrated in thick, laterally extensive sandstone bodies in the central-southeast portion of the study area.