--> Correlating Water Imbibition to Geology in Montney Formation Using Core and Log Data

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Correlating Water Imbibition to Geology in Montney Formation Using Core and Log Data

Abstract

The Montney Formation in Alberta and British Columbia contains an estimated 400 Tcf in gas reserves and a large number of oil and condensate discoveries. Though often described as a shale reservoir in literature, it is in fact a siltstone. Siltstones have not been studied as extensively compared to sandstone or shale reservoirs. It is therefore challenging to predict petrophysical properties, and the water and hydrocarbon distribution in the Montney with the current state of knowledge. Due to the low porosity and permeability values (<5% and <5 md respectively), hydraulic fracturing is required to obtain economic wells in the Montney. Matrix imbibition is an important factor with both financial and environmental implications, dictating how much of the hydraulic fracturing fluid returns to the well bore. Imbibition is influenced by the capillary pressure and the wettability of the rock. Capillary pressure is in turn related to the pore throat size distribution which correlates with mineralogy (mainly clay content and type) and the organic carbon content. In this study we propose relationship between the volume of water imbibed by the formation during hydraulic fracturing and the geological data obtained from well logs. Our data set including inorganic rock composition from QEMSCAN, petrographic analysis of thin sections and SEM imaging, inorganic rock composition from LECO TOC analysis, permeability measurements of confined samples, and porosity and capillary pressure measurements from mercury injection analysis. Minerals includes quartz, feldspar, plagioclase, carbonate minerals, pyrite, apatite, muscovite and clay minerals (MILS, Illite, and chlorite). TOC values range between 0.1% and 5.4%, Permeability between 10-6 and 10-2 md, porosity between 2% and 4%′ with an average of 2.8% and an average pore throat size of 0.008 and 0.02 μm. We apply statistical analyses to relate organic/inorganic rock composition and mercury injection results (porosity, pore throat size, and capillary pressure values), determined from core samples, to a suite of well logs (including gamma-ray, density porosity, neutron porosity, resistivity, and sonic). The porosity and the pore throat radius measurements from the cores are incorporated in a numerical model to predict the rate and the volume of water imbibition. The numerical model is verified using experimental measurements of spontaneous imbibition in shale cores.