An investigation into the interrelationship between petrophysical properties of potential gas shale reservoirs from Western Australia

An investigation into petrophysical properties of potential gas shales from the Perth and Canning Basins has been performed to understand the interrelationship between shale composition, geochemical properties and pore structural parameters. The following measurements were done on the samples:• Low pressure nitrogen adsorption and mercury porosimetry technique for determination of the pore structural properties,• Gas expansion method for determining the effective porosity,• High pressure methane adsorption for determination of the adsorbed gas capacity

Petrophysical Evaluation of Gas shale Reservoirs

For many years, shale formations were viewed as a hydrocarbon source rock or cap rock. Due to this traditional point of view, only geochemical analysis has been routinely performed on the shale layers. However, for sweet spot mapping of the gas shale layers, it is necessary to know about petrophysical and geomechanical properties as well as geochemical ones. The main focus of this chapter is the petrophysical evaluation methods of shale formations. In the first section, the key properties for evaluation of potential gas shale intervals are defined, and then the available techniques for measuring these parameters will be discussed. The chapter will be wrapped up with the common well log signatures of the gas shales and how to interpret them for finding petrophysical properties of shale intervals

Comparisons of pore size distribution: A case from the Western Australian gas shale formations

Pore structure of shale samples from Triassic Kockatea and Permian Carynginia formations in the Northern Perth Basin, Western Australia is characterized. Transport properties of a porous media are regulated by the topology and geometry of inter-connected pore spaces. Comparisons of three laboratory experiments are conducted on the same source of samples to access such micro-, meso- and macro-porosity: (i) Mercury Injection Capillary Pressure (MICP), (ii) low field Nuclear Magnetic Resonance (NMR) and nitrogen adsorption (N2). High resolution FIB/SEM image analysis is used to further support the experimental pore structure interpretations at sub-micron scale. A dominating pore throat radius is found to be around 6 nm within a meso-pore range [2 nm – 50 nm] based on MICP, with a common porosity around 3%. This relatively fast experiment offers the advantage to be reliable on well chips or cuttings up the pore throat sizes > 2 nm. However, nitrogen adsorption method is capable to record pore sizes below 2 nm through the determination of the total pore volume from the quantity of vapour adsorbed at relative pressure. But the macro-porosity and part of the meso-porosity is damaged or even destroyed during the sample preparation. BET specific surface area results usually show a narrow range of values from 5 to 10 m2/g. Inconsistency was found in the pore size classification between MICP and N2 measurements mostly due to their individual lower- and upper-end pore size resolution limits. In hand, the water filled pores disclosed from NMR T2 relaxation time were on average 30% larger than MICP tests. Evidence of artifical cracks generated from the water interactions with clays after re-saturation experiments could explain such porosity over-estimation. It is therefore fundamental to work on preserved shale gas to properly assess the porosity and pore distribution from NMR. The computed pore body to pore throat ratio extracted from the Timur-Coates NMR model, calibrated against gas permeability experiments, revealed that such pore geometry directly control the permeability while the porosity and pore size distribution remain similar between different shale gas formations and/or within the same formation. The combination of pore size distribution obtained from MICP, N2 and NMR seems appropriate to fully cover the range of pore size from shale gas and overcome the individual method limits

The Importance of Geochemical Parameters and Shale Composition on Rock Mechanical Properties of Gas Shale Reservoirs: a Case Study From the Kockatea Shale and Carynginia Formation From the Perth Basin, Western Australia

Evaluation of the gas shale mechanical properties is very important screening criteria for determining the potential intervals for hydraulic fracturing and as a result in gas shale sweet spot mapping. Young’s modulus and Poisson’s ratio are two controlling mechanical properties that dictate the brittleness of the gas shale layers. These parameters can be determined in the laboratory by testing the rock sample under different conditions (static method) or can be calculated using the well-logging data including sonic and density log data (dynamic method). This study investigates the importance of the shale composition and geochemical parameters on the Young’s modulus and Poisson’s ratio using log data. The data set of this study is coming from five different wells targeting the Kockatea Shale and Carynginia formation, two potential gas shale formations in the Perth Basin, Western Australia. The results show that converse to the common idea the effect of organic matter quantity and maturity on the rock mechanical properties of the gas shale reservoirs is not so much prominent, while the composition of the rock has an important effect on these properties. Considering the weight percentage of shale composition and organic matter quantity it could be concluded that effect of these parameters on rock mechanical properties is dependent on their weight contribution on the shale matrix. As well as effect of thermal maturity on the shale matrix and consequently on the rock mechanical properties of the shale is dependent on the organic matter content itself; therefore, obviously with a low organic matter content thermal maturity has no prominent effect on the brittleness as well