Near-wellbore alteration in shear stiffnesses in the three orthogonal planes can be described in terms of radial variations of the three shear moduli or slownesses. The three shear moduli are different in formations exhibiting orthorhombic or lower degree of symmetry, as is the case in deviated wellbores in triaxially stressed formations. These shear moduli are affected by factors such as overbalanced drilling, borehole stress concentrations, shale swelling, near-wellbore mechanical damage, and supercharging of permeable formations. The two vertical shear moduli C 44 and C 55 in an anisotropic formation with a vertical x 3 -axis are obtained from crossed-dipole sonic data, whereas the horizontal shear modulus C 66 is estimated from borehole Stoneley data. The effective shear modulus C 66 is smaller than the vertical shear moduli C 44 or C 55 in a poroelastic formation exhibiting high horizontal fluid mobility. Consequently, analyses of radial profiling of the three shear moduli in a reasonably uniform lithology interval yield useful correlations, with mobility impaired by an increased amount of clay or by near-wellbore damage in a shaley sand reservoir interval in a North Sea vertical well. Radial profiling results help to identify suitable depths for fluid sampling and to complete a well for optimum production.

The Nuclear Magnetic Resonance (NMR) response of gas in gas shale nanopores is different from that of bulk gas, where relaxation is dominated by spin rotation and diffusion is unrestricted. Gas shales are characterized by very low porosity and ultra low permeabilities. Their porosity is dominated by nanometer-scale pores in the organic kerogen that restricts diffusional motion, in addition to having very high surface-to-volume ratios that enhance surface relaxation. At high pressure, the gas exists as an adsorbed phase on the pore surface and as free gas phase in the pore interior. Thus, relaxation and diffusion properties of gas in gas shales are controlled by the combined effects of adsorption, enhanced surface relaxation, restricted diffusion and molecular exchange between the adsorbed and free phases. One of the biggest challenges is the understanding of such effects in order to determine the quantity of free and adsorbed gas from NMR data, and to devise novel techniques to log these unconventional plays. Proper estimation of fluid volumes also requires the knowledge of the hydrogen index for the gas restricted in the gas shale nanopores, which is yet another challenge. The NMR responses of methane gas in Haynesville shale plugs cored from a well in East Texas, USA were studied in laboratory experiments using a 2 MHz NMR spectrometer at elevated pressures up to 5 kpsi. The effects of adsorption, surface relaxation and restricted diffusion have been characterized, and the hydrogen index of the gas has been measured. Mineralogy, elemental analysis and Brunauer-Emmett-Teller (BET) experiments have also been carried out on the same plugs to understand the formation characteristics. In the samples studied, faster relaxation modes (few tens of milliseconds) and slower apparent diffusion coefficients (an order of magnitude less than their bulk values) for the confined gas molecules in comparison to their bulk properties have been observed for the first time with the help of 2D-NMR experiments at high pressure. It has been observed that the relaxation spectra for bound water and the gas in the small pores overlap. Additional information is required to resolve these two fluids. Subsequently, the diffusion dimension is investigated to resolve the various fluids in the nanopores. We formulate new relaxation and diffusion models for the interpretation of the dynamics of gas restricted in gas shale and propose that multi-dimensional NMR logging with pulse sequences optimized for gas shales be further tested in the field, to help quantify the total gas in place.

A well drilled in the Green River formation in Colorado on the Bureau of Land Management RD&D lease of American Shale Oil LLC (AMSO), provides an opportunity to compare core measurements and log-derived properties in a unique unconventional resource reservoir. The core was analyzed for matrix density, Fischer Assay, total organic carbon (TOC), mineralogy, and 58 inorganic elemental concentrations. Logs include neutron, density, gamma ray, resistivity, magnetic resonance, and inelastic and capture nuclear spectroscopy. The data from this well are used to demonstrate new methodologies to estimate the TOC content and Fischer Assay oil yield.The TOC content is estimated in three ways. The first is a multitool petrophysical evaluation. The second is an estimation of kerogen from the difference between density and magnetic resonance (MR) porosities where MR porosity corresponds to the water-filled porosity and density porosity to the sum of kerogen-and water-filled porosity. The third method combines inelastic and capture nuclear spectroscopy log data to compute elemental concentration logs of total carbon, inorganic carbon, and TOC.For comparison of core mineralogy and chemistry with log data, over 200 intervals of core from this well were sampled as 2ft-long slabs that were ground and homogenized, approximating the vertical resolution of log responses. The agreement between the logs and core values for total carbon, total inorganic carbon, and TOC is very good. The TOC log is used to activate empirical relationships such as Fischer Assay oil shale grade from TOC, again with good results.