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