We introduce a new quantitative approach to improve the petrophysical evaluation of thinly bedded sand-shale sequences that have undergone extensive diagenesis. Formations under analysis consist of carbonate-rich clastic sediments, with pore system heavily reworked by calcite and authigenic clay cementation, giving rise to rocks with high spatial heterogeneity, low porosity, and low permeability. Porosity varies from 2 to 20% and permeability varies from less than 0.001 mD to 200 mD. Diagenesis and thin laminations originate complex magnetic resonance (NMR) T2 distributions exhibiting multimodal distributions. Furthermore, reservoir units produce highly viscous oil, which imposes additional challenges to formation evaluation. Petrophysical evaluation of thinly bedded formations requires accurate estimation of laminar and dispersed shale concentration. We combined Thomas-Stieber’s method, OBMI, and Rt-Scanner measurements to calculate laminar shale concentration. Results indicate that hydrocarbon reserves can be overestimated in the presence of high-resistivity streaks and graded beds, which give rise to electrical anisotropy. To account for electrical anisotropy effects on petrophysical estimations, we classified reservoir rocks based on the cause of electrical anisotropy. Thereafter different interpretation methods were implemented to estimate petrophysical properties for each rock class. We also appraised the advantages and limitations of the high-resolution method for evaluating thinly bedded formations with respect to other petrophysical interpretation methods. Numerical simulations were performed on populated earth-model properties after detecting bed boundaries from resistivity or core images. Earth-model properties were iteratively refined until field and numerically simulated logs reached an acceptable agreement. Results from the high-resolution method remained petrophysically consistent when beds were thicker than 0.25 ft. Numerical simulations of NMR T2 distributions were also performed to reproduce averaging effects of NMR responses in thinly bedded formations, which enabled us to improve the assessment of pore-size distributions, in-situ fluid type, and saturation. Permeability of sand units was estimated via Timur-Coates’ equation by removing the effect of laminar shale on porosity and bulk irreducible volume water. Shoulder-bed corrected logs were input to the calculations. Petrophysical properties obtained with the developed interpretation method honor all the available measurements including conventional well logs, NMR, resistivity images, multi-component induction, and core measurements. The developed interpretation method was successfully tested across four hydrocarbon-saturated intervals selected from multiple wells penetrating a deep turbidite system. Permeability values obtained with the new interpretation method improved the correlation with core measurements by 16% as compared to permeability calculations performed with conventional methods. In addition, on average the method yielded a 62% increase in hydrocarbon pore-thickness when compared to conventional petrophysical analysis. / text

Reliable assessment of static and dynamic petrophysical properties of hydrocarbon-bearing reservoirs is critical for estimating hydrocarbon reserves, identifying good production zones, and planning hydro-fracturing jobs. Conventional well-log interpretation methods are adequate to estimate static petrophysical properties (i.e., porosity and water saturation) in formations consisting of thick beds. However, they are not as reliable when estimating dynamic petrophysical properties such as absolute permeability, movable hydrocarbon saturation, and saturation-dependent capillary pressure and relative permeability. Additionally, conventional well-log interpretation methods do not take into account shoulder-bed effects, radial distribution of fluid saturations due to mud-filtrate invasion, and differences in the volume of investigation of the various measurements involved in the calculations. This dissertation introduces new quantitative methods for petrophysical and compositional evaluation of water- and hydrocarbon-bearing formations based on the combined numerical simulation and nonlinear joint inversion of conventional well logs. Specific interpretation problems considered are those associated with (a) complex mineral compositions, (b) mud-filtrate invasion, and (c) shoulder-bed effects. Conventional well logs considered in the study include density, photoelectric factor (PEF), neutron porosity, gamma-ray (GR), and electrical resistivity. Depending on the application, estimations yield static petrophysical properties, dynamic petrophysical properties, and volumetric/weight concentrations of mineral constituents. Assessment of total organic carbon (TOC) is also possible in the case of hydrocarbon-bearing shale. Interpretation methods introduced in this dissertation start with the detection of bed boundaries and population of multi-layer petrophysical properties with conventional petrophysical interpretation results or core/X-Ray Diffraction (XRD) data. Differences between well logs and their numerical simulations are minimized to estimate final layer-by-layer formation properties. In doing so, the interpretation explicitly takes into account (a) differences in the volume of investigation of the various well logs involved, (b) the process of mud-filtrate invasion, and (c) the assumed rock-physics model. Synthetic examples verify the accuracy and reliability of the introduced interpretation methods and quantify the uncertainty of estimated properties due to noisy data and incorrect bed boundaries. Several field examples describe the successful application of the methods on (a) the assessment of residual hydrocarbon saturation in a tight-gas sand formation invaded with water-base mud (WBM) and a hydrocarbon-bearing siliciclastic formation invaded with oil-base mud (OBM), (b) estimation of dynamic petrophysical properties of water-bearing sands invaded with OBM, (c) estimation of porosity and volumetric concentrations of mineral and fluid constituents in carbonate formations, and (d) estimation of TOC, total porosity, total water saturation, and volumetric concentrations of mineral constituents in the Haynesville shale-gas formation. Comparison of results against those obtained with conventional petrophysical interpretation methods, commercial multi-mineral solvers, and core/XRD data confirm the advantages and flexibility of the new interpretation techniques introduced in this dissertation for the quantification of petrophysical and compositional properties in a variety of rock formations. / text