Petrophysical characterization and quantification of OOIP/OGIP and producibility in tight rock unconventional (TRU) and shale reservoirs remains challenging. The porosity system of these reservoirs is dominated by nano and micro pores, while the matrix system is formed by the mixture of regular shale and kerogen with different maturities. Therefore the total porosity in an unconventional reservoir is often less than 10PU (porosity unit, or percentage of total volume), and the permeability ranges from nano to micro Darcy. Storage and transport of hydrocarbon varies with the percentage and maturity of the organic material in TRU and shale formations, and impacts up to 20% of OOIP/OGIP. Evaluation of porosity, saturation, and matrix permeability from conventional logs becomes very difficult and often requires a large number of core measurements to correctly define the rock and pore system.
Routine NMR workflows for characterizing conventional reservoirs cannot directly be used to derive petrophysical properties in TRU formations. Through laboratory NMR core analysis and NMR logging field trials in various TRU and shale reservoirs, we have developed a new NMR shale interpretation workflow that focuses on
obtaining high-quality raw echo data by optimizing data activation sequences for TRU and shale formations,
improving the data processing scheme by enhancing T2 resolution to separate different fluid components in T2 distributions,
adapting a new fluid typing method that only involves clay-bound water and capillary bound fluids, part of which is also producible, and
using NMR core analysis to verify the cutoff and T1/T2 ratio trend to improve fluid identification in TRU and shale reservoirs.
The workflow has been successfully applied to evaluate petrophysical properties in the Marcellus and Vaca Muerta formations. It reduces the uncertainty of total porosity and free fluid volume (FFV), and identifies fluid types and sweet spots.
