Recent advances in logging-while-drilling sigma measurements include three-detector thermal-neutron and gamma-ray decay measurements with different radial sensitivities to assess the presence of invasion. We have developed an inversion-based work flow for the joint interpretation of multidetector neutron, density, and sigma logs to reduce invasion, shoulder-bed, and well-deviation effects in the estimation of porosity, water saturation, and hydrocarbon type, whenever the invasion is shallow. The procedure begins with a correction for matrix and fluid effects on neutron and density-porosity logs to estimate porosity. Multidetector time decays are then used to assess the radial length of the invasion and estimate the virgin-zone sigma while simultaneously reducing shoulder-bed and well-deviation effects. Density and neutron porosity logs are corrected for invasion and shoulder-bed effects using two-detector density and neutron measurements with the output from the time-decay (sigma) inversion. The final step invokes a nuclear solver in which corrected sigma, inverse of migration length, and density in the virgin zone are used to estimate water saturation and fluid type. The fluid type is assessed with a flash calculation and Schlumberger’s Nuclear Parameter calculation code to account for the nuclear properties of different types of hydrocarbon and water as a function of pressure, temperature, and salinity. Results indicate that accounting for invasion effects is necessary when using density and neutron logs for petrophysical interpretation beyond the calculation of total porosity. Synthetic and field examples indicate that the mitigation of invasion effects becomes important in the case of salty mud filtrate invading gas-bearing formations. The advantage of the developed inversion-based interpretation method is its ability to estimate layer-by-layer petrophysical, compositional, and fluid properties that honor multiple nuclear measurements, their tool physics, and their associated borehole geometrical and environmental effects.

Radioactive chemical sources can pose security, health, and environmental risks when used to estimate rock porosity in situ. The oil industry has been developing solutions to eliminate radioactive chemical sources in borehole nuclear logging. Pulsed neutron generators have successfully replaced chemical sources in neutron tools, but cesium-137 is still mainly used for borehole density measurements. Neutron-activated gamma-ray measurements (neutron-gamma) are a possible alternative to radioactive chemical sources in density tools. Despite recent advances, the measurement faces challenges regarding density accuracy across diverse solid and fluid rock compositions and nonnegligible sensitivity to borehole environmental effects. We have examined a theoretical, albeit realistic, logging-while-drilling neutron-gamma density (NGD) tool operating with two inelastic gamma-ray detectors and two fast neutron detectors. With a strong emphasis on measurement physics and source-sensor design, the tool delivers density accuracies comparable to those of gamma-gamma density (GGD) tools with [Formula: see text] error in shale-free formations and [Formula: see text] in shale and shaly formations. Our work also compares NGD with GGD in terms of depth of investigation (DOI), vertical resolution, and sensitivity to borehole environmental effects to determine optimal logging conditions. NGD accuracy is limited in the presence of standoff. With inputs of caliper and mud type, empirical density corrections can be applied up to 0.64 cm (0.25 in) standoff. NGD also has limited applicability in thinly bedded formations with maximum vertical resolution of 76 cm (2.5 ft). However, the measurement outperforms GGD in the presence of invasion because its DOI is twice as large.

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The rock-pore textural properties in unconventional fine-grained reservoirs are much more complicated than in conventional reservoirs. In fine-grained rocks, this complexity derives from very small component grain assemblages (clay and silt fractions) and very small pores (nano- to microsizes) overprinted by diagenesis. It is further compounded by the pores being developed in intergranular, grain dissolution, and organic-associated-intragranular voids. Additionally, because locally sourced hydrocarbons in unconventional reservoirs, in contrast to migrated hydrocarbons that are present in conventional reservoirs, exist within similar pore sizes as the original saturating water phase, they create geometrically complex fluid distributions. These imply that, in the context of nuclear magnetic resonance (NMR) logging and petrophysical interpretation of tight oil unconventional reservoirs, pore size can no longer be considered a proxy for fluid type and vice versa. This means using T2 or T1 cutoffs may give inaccurate predictions. Current industry applications of NMR T1-T2 logging have demonstrated reliable interpretation of fluid types and water saturation. However, because petrophysical controls of advanced relaxation effects (such as surface and bulk fluid relaxation properties, pore-size distribution, and wettability) are not properly understood, these applications have been limited to estimating fluid saturations and have not been applied to estimating pore sizes. We extend the application of NMR T1-T2 measurements in tight oil unconventional reservoirs to model pore-size distributions by using apparent surface relaxivities and bulk relaxation times that have been jointly estimated from poro-fluid relaxations. To test these predictions, modeled pore-size distributions are compared to rock-pore textural properties from petrographic images of core samples. Such comparison allows us to derive insights into controls of mudstone reservoir quality (RQ) in conjunction with the impact of rock fabric endmembers (e.g., matrix-supported clays, grain-supported framework, diagenetic cements, and solid organic matter) on pore-size distributions. With these assumptions in mind, it follows, based on the Kozeny-Carman formulation, that unconventional rock permeability is reliably predicted from the NMR-based pore-size distributions. Furthermore, we deduce the impact of mineral assemblages in the Herron permeability model to infer influence on rock textural properties and ultimately predict permeability in limited data environments. This paper introduces a novel approach to estimate pore-size distributions per fluid type (water and hydrocarbons) from NMR T1-T2 measurements in unconventional reservoirs. Additionally, petrophysical controls of RQ, storage, and transport properties are derived from NMR-based pore-size distributions and mineral assemblages. This enables more reliable RQ and permeability assessment than typical T2- or T1-cutoff methods.