Browsing by Subject "Formation evaluation"
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Item Estimation of fluid-transport properties of rocks based on X-ray radiography and numerical simulation of two-phase immiscible fluid displacement(2023-07-26) Aérens, Pierre Philippe Yves Roger; Torres-Verdín, Carlos; Balhoff, Matthew; Espinoza, David Nicolas; Ketcham, Richard; Lake, LarryHeterogeneity and anisotropy of fluid-bearing rocks remain a challenge of central importance in the quantification of subsurface energy resources. Borehole geophysical measurements are the principal source of data used to quantify in situ rock properties, but they are often riddled with uncertainty resulting from the combined effects of rock heterogeneity/anisotropy and mud-filtrate invasion. This uncertainty often persists in geological formations deemed homogeneous. Accurate interpretation of borehole geophysical measurements requires modeling of multiphase flow resulting from invasion of mud filtrate into porous and permeable rocks. For the specific case of spatially complex rocks, there is a need for experimental and numerical methods that integrate all pertinent information about the interactions between fluids (including mud filtrate) and rocks to develop realistic models of fractional flow, i.e., saturation-dependent relative permeability and capillary pressure in the near-wellbore region. This dissertation combines new laboratory measurements with numerical simulations to estimate fluid-transport properties of spatially complex rocks subjected to two-phase immiscible fluid displacement. At the heart of these experimental procedures is a new high-resolution imaging technique based on X-ray radiography that uses a microfocus computed tomography scanner and thin rectangular rock samples to (a) capture and quantify fluid displacement patterns, (b) provide time-lapse images of fluid distribution, and (c) visualize external and internal mudcake deposition. The work also includes the development of a new method to appraise the quality of nuclear magnetic resonance measurements used to quantify rock-pore structure. Injection experiments were performed to study the impact of connate fluid properties, drilling fluid properties, and rock petrophysical properties on two-phase flow taking place during mud-filtrate invasion, injection, or production. Experimental and numerical results indicate that the spatial distribution of fluids (both connate fluids and mud filtrate), flow patterns, and mudcake deposition resulting from mud-filtrate invasion depend heavily on the nature and degree of rock heterogeneity, bedding plane orientation, and anisotropy during both drainage and imbibition. In rocks considered homogeneous, fluid displacements approach piston-like behavior, as predicted by the Buckley-Leverett theory of fractional flow, while in spatially complex rocks, high-resolution time-lapse images uncover preferential flow paths along high-permeability sections of the rock, hence giving rise to low sweep efficiency. At late experimental times, both the spatial distribution of fluids and sweep efficiency are significantly influenced by variations in capillary pressure and transmissibility across the rock sample. Laboratory experiments also emphasize the impact of viscous and/or capillary forces on two-phase flow behavior during mud-filtrate invasion. It is found that mud properties dominantly control both invasion rate and mudcake thickness growth, independently of rock properties. The new hybrid laboratory-simulation approach is effective for examining the time evolution of fractional flow, as it offers an alternative to the laborious and time-consuming traditional steady-state laboratory methods used for measuring relative permeability and capillary pressure. Furthermore, the new laboratory methods introduced in this dissertation are fast and reliable to simultaneously assess flow-related petrophysical properties of spatially complex rocks and to examine competing fluid displacement mechanisms. Overall, the combination of experimental and numerical results improves our understanding of two-phase immiscible flow in heterogeneous rocks and of the various effects that mud-filtrate invasion can have on borehole geophysical measurements during or after drilling operations. This new approach foreshadows new interpretation methods for production-oriented formation evaluation.Item In-situ visualization and characterization of mud-filtrate invasion and filter cake deposition using time-lapse X-ray micro-computed tomography (micro-CT)(2022-05-03) Schroeder, Colin Lucas; Torres-Verdín, Carlos; Kerans, C. (Charles), 1954-; Tisato, Nicola; Loucks, RobertBorehole measurements acquired during and shortly after drilling of oil and natural gas wells are often subject to uncertainty resulting from the effects of mud-filtrate invasion. Accurate interpretation of these measurements requires a thorough understanding of the invasion process, including the deposition of filter cake, or mudcake, on the borehole wall and the flow of mud filtrate around the wellbore. Failure to properly account for these effects can lead to inaccurate estimation of petrophysical properties, errors in the quantification of hydrocarbon reserves, and misinformed long-term investment decisions. In this work, we designed and performed novel laboratory experiments that involved water- and synthetic oil-based mud-filtrate invasion in cylindrical rock core samples of varying petrophysical properties. Using high-resolution X-ray micro-computed tomography (micro-CT), we were able to visualize and characterize mudcake deposited on the borehole wall and the distribution of mud filtrate in the core samples as a function of both space and time during the experiments. Additionally, with the aid of a new set of generalized filtration equations, we were able to reliably estimate average in-situ mudcake properties, including mudcake porosity and permeability, during the experiments. Experiments were performed to study the influence of drilling fluid properties and rock petrophysical properties on the process of mud-filtrate invasion. Results for the rate of mud-filtrate invasion and the time evolution of mudcake thickness were consistent with behavior predicted by the derived generalized filtration equations. For rock core samples with permeability exceeding 8.9 mD, aside from a brief initial period of spurt loss, the mud-filtrate invasion rate was primarily controlled by the properties of the deposited mudcake rather than the distinct petrophysical properties of the core samples. In-situ mudcake properties, including porosity and permeability, generally remained constant while mudcake was thin, justifying the use of average in-situ values with models derived assuming incompressible mudcake. Filtrate flow through the core samples, including the movement of the invasion front and the redistribution of mud filtrate within the invaded zone, was strongly influenced by capillary forces, which caused deeper, more-uniform invasion than would be expected in the absence of capillary-driven flow, both in homogeneous and spatially heterogeneous rocks.Item Multiscale, image-based interpretation of well logs acquired in a complex, deepwater carbonate reservoir(2017-05) Victor, Rodolfo Araujo; Prodanović, Maša; Torres-Verdín, Carlos; Bryant, Steven L; Fomel, Sergey; Heidari, ZoyaCarbonate formations hold a large percentage of the world's hydrocarbon reserves. Their petrophysical evaluation via well logs and core data faces significant technical challenges because of the coexistence of multiscale pore features affecting fluid-transport phenomena. The combined effects of diagenesis, solid dissolution, and recrystallization in carbonate rocks give rise to pores ranging from centimeter-size vug openings to submicron microporosity. In turn, the wide variability of pore sizes, pore shapes, pore textures, and pore connectivity gives rise to multiple length-dependent flow regimes. % New data sources have allowed many porous-media processes to be observed or numerically simulated in detail for the first time; they have also helped to understand flow mechanisms that have a direct impact on hydrocarbon recovery. Spatial imaging techniques such as computed tomography (CT) are now applied routinely to acquire 3D images of both laboratory samples and whole core. Those images reveal fine features of rock structure, pore topology, and mineral spatial distribution, in addition to enabling the numerical simulation of several physical phenomena taking place inside the pore space. Methods used to analyze rock properties based on 2D and 3D digital images are collectively known as digital rock petrophysics, and are being used at an accelerated pace to quantify the storage and production potential of spatially complex rocks. This dissertation introduces new quantitative methods for the analysis of whole-core CT images to improve the interpretation of well logs acquired in carbonate formations. % The first method focuses on the estimation of density and atomic number from dual-energy CT core scans. A new Monte Carlo-based inversion algorithm for estimating such properties is developed to account for uncertainties in X-ray attenuation coefficients in addition to delivering uncertainty estimates of inversion products. Estimation of electron density and effective atomic number from CT core scans enables direct deterministic or statistical correlations with salient rock properties for improved petrophysical evaluation. Verification tests of the inversion method performed with CT-generated density and PEF logs yield very good agreement with borehole measurements of density and photoelectric factor. Next, a new workflow is introduced for image segmentation and interpretation. Reliable classification of image voxels in components representing grains, pores, and sub-resolution features remains challenging in images with multiscale features such as those of carbonate whole cores. The new workflow reduces statistical bias introduced by interpreter subjectivity, and allows automation for the analysis for a large number of samples. Segmentation of vug space in CT images also enables close inspection and reliable interpretation of well logs in vuggy reservoir regions. Connected vugs are expected to exhibit high and dominant fluid production capacity, whereby the ability to properly identify such reservoir zones via well logs is very important. Ultrasonic borehole images have been extensively used to assess rock texture and multiple geometrical and sedimentary features. Comparison of ultrasonic borehole images to CT data confirms specific well-log responses across vuggy depth segments. New feature-enhancing methods are introduced for the interpretation of ultrasonic borehole images. However, no strong correlation was found when attempting to quantify vuggy porosity from various image attributes. % The segmentation of CT images across vuggy space is also explored for estimating vug flow properties. A statistical description of segmented vuggy space is suggested to estimate permeability given the relatively low image resolution of the available CT data. Results confirm the hypothesis that connected vugs dominate fluid flow, whereby the assessment of vug geometrical properties provides sufficient information for estimating permeability. Finally, a new method is introduced for the interpretation of nuclear magnetic resonance (NMR) logs. Adverse borehole conditions such as mud-filtrate invasion and large washouts in vuggy zones are usually neglected in conventional interpretation procedures of NMR logs. To circumvent the latter problem, we describe the measured distribution of transverse relaxation times as the superposition of a finite set of log normal components where each component accounts for specific relaxation rates for drilling mud and original formation fluids. Estimated permeabilities in vuggy zones from NMR logs with the new method are more accurate than those rendered by conventional techniques based on cutoff values or logarithmic averages. The method also explicitly quantifies vuggy porosity, which is found to be in good agreement with values obtained from segmented CT data. The combined use of the above interpretation methods confirms the value of digital rock techniques to improve the interpretation of well logs acquired in complex carbonate formations, specifically in the calculation of permeability across vuggy depth segments. Results can be used to improve the interpretation of well logs acquired in wells devoid of core data and/or high-resolution borehole images.Item Perturbation methods for rapid modeling and inversion of single-phase pressure diffusion measurements(2017-08-11) Escobar Gomez, Juan Diego; Torres-Verdín, Carlos; Sepehrnoori, Kamy; Balhoff, Matthew; Heidari, Zoya; Alpak, Faruk ONumerical simulation enables improved quantitative understanding of pressure diffusion phenomena in spatially complex reservoirs. Despite recent computational advances, traditional numerical simulation algorithms still pose significant challenges in flexibility and computer performance, especially concerning the solution of time-domain problems that require multiple implementations of a forward model. In this dissertation I develop a time-domain perturbation theory suitable for modeling anisotropic and heterogeneous single-phase flow systems. Although theoretically valid for any spatially-dependent rock/fluid property, the study emphasizes arbitrary spatial variations of tensorial permeability. The efficiency of integral-equation solutions is invoked by coupling perturbation theory and the superposition principle to accurately model arbitrary transient flow regimes, boundary conditions, and rockproperty distributions. Developed algorithms require a maximum of two numerical simulations to construct flow-history-dependent Permeability Sensitivity Functions (PSF) for the entire spatial-temporal domain. Rapid Forward Modeling (RFM) of pressure transients is implemented via perturbed-type solutions by weighing the sensitivity functions with spatial permeability perturbations. Regardless of the gradient-based technique, Rapid Inverse Modeling (RIM) of hydraulic measurements is also approached by efficiently adapting the sensitivity functions to calculate the entries of the associated Jacobian matrix. Research findings confirm the flexibility and reliability of perturbation methods after successful validation with numerical reservoir simulators in both cylindrical and Cartesian coordinates. Multidimensional synthetic studies modeling hydraulic-testing tools and multi-well conditions were examined for diverse anisotropic, heterogeneitydominated fluid-flow regimes. With perturbations of more than one order of magnitude in background permeability, it was found that perturbed-type solutions can be obtained in approximately three orders of magnitude less CPU time compared to conventional finitedifference methods, with relative errors in pressure as low as < 7%. Additionally, the use of sensitivity functions for (1) selecting the subset of measurements input to the estimation of spatial distributions of permeability and (2) reducing the sequential calculation of Jacobian matrices invoked by nonlinear, gradient-based inversion, provide a stable and efficient alternative for the quantitative interpretation of single-phase transient pressure measurements.Item Physics and rapid forward modeling of logging-while-drilling Neutron-Gamma density measurements(2018-02-21) Luycx, Mathilde Michèle; Torres-Verdín, Carlos; Charlton, William; Daigle, Hugh; Heidari, Zoya; Sepehrnoori, KamyAlthough radioactive chemical sources have long been used in borehole nuclear tools for in-situ porosity estimation, they pose non-negligible health, safety, and environmental risks. Pulsed neutron generators were successfully introduced as replacements for americium-beryllium (AmBe) sources in neutron-based measurements. However, bulk density is still generally measured using Gamma-Gamma density tools operating with cesium-137 sources. Neutron-activated gamma-ray measurements (Neutron-Gamma) are a safer alternative to Gamma-Gamma density measurements because cesium-137 is replaced with a pulsed neutron generator. Thereafter, bulk density is estimated from neutron-induced non-capture gamma-ray counts corrected for neutron transport. Field studies with commercial Neutron-Gamma density tools revealed several practical limitations, including sensitivity to borehole conditions and decreased accuracy in high-density formations, shales, and shaly formations. The main purpose of this dissertation is to develop new measurement and interpretation procedures to mitigate such limitations. With the objective of accurately capturing the measurement physics, I designed a new theoretical, albeit realistic logging-while-drilling (LWD) Neutron-Gamma density tool. This new tool combines inputs from two gamma-ray detectors and two fast neutron detectors to deliver density accuracies that favorably compare to those obtained with traditional Gamma-Gamma density measurements, i.e., 0.013 g/cm³ in shale-free formations, and 0.019 g/cm³ in shale and shaly formations. Similar to other nuclear measurements, Neutron-Gamma density is affected by bed-boundary and layer-thickness effects that can mask the true formation bulk density when implementing conventional interpretation methods. Borehole environmental effects are additionally mitigated using empirical corrections because “spine-and-rib” compensation is impractical. However, for standoff values greater than 0.63 cm (0.25 in), such empirical corrections should be avoided as they no longer remain independent of formation properties. Three-dimensional geometrical and borehole effects can be mitigated using fast numerical simulations coupled with inversion-based interpretation. To simulate borehole LWD Neutron-Gamma density measurements, I developed a fast-forward modeling algorithm based on first-order approximations and flux sensitivity functions. The algorithm is over 500,000 times faster than industry-standard Monte Carlo methods and achieves root-mean-square errors of less than 1% (0.023 g/cm³) in formations with spatially complex geometry, including high-angle wells, thinly-bedded formations, and invaded beds. However, fast numerical simulations based on first-order approximations have limited accuracy when modeling borehole environmental effects. The Neutron-Gamma density fast-forward algorithm can improve the interpretation of measurements when standoff is less than 1.27 cm (0.5 in). Conversely, for larger values of standoff, spatial flux perturbations give rise to higher-order measurement responses that are not captured with first-order approximations, yielding density errors of up to 0.04 g/cm³ for 2.54 cm (1 in) standoff. The second part of this dissertation introduces new methods to improve borehole environmental corrections of nuclear measurements based on single-particle transport. They rely on higher-order rapid forward simulations wherein sensitivity flux perturbations are quantified using approximations to the Boltzmann transport equation. For neutron measurements, the diffusion flux-difference method is enhanced with a two-step algorithm that minimizes the size of the perturbation and yields average errors of 1 porosity unit (p.u.) in boreholes with up to 2.5-cm (1-in) standoff. For Gamma-Gamma density measurements, the gamma flux-difference (GFD) method is introduced to quantify gamma-ray flux perturbations using exponential point kernels and a Rytov approximation. This latter procedure yields maximum density errors of 0.02 g/cm³ in boreholes with up to 4.44 cm (1.75 in) standoff. The methods developed in this dissertation represent the first step toward future improvements in fast modeling of borehole environmental effects for nuclear measurements based on coupled neutron and gamma-ray transport, such as Neutron-Gamma densityItem Probabilistic petrophysical and compositional interpretation of well logs and core data via Bayesian inversion(2022-05-06) Deng, Tianqi; Torres-Verdín, Carlos; Sepehrnoori, Kamy; Heidari, Zoya; Espinoza, Nicolas; Sen, MrinalA critical component of Formation Evaluation is the estimation of in situ petrophysical properties and solid/fluid composition of rocks from multiple well logs and core laboratory measurements. Commercial software solutions abound; they typically use linear/quasi-linear multi-mineral analysis to calculate the concentrations of rock solid/fluid constituents from multiple well logs. However, these methods are often susceptible to abnormal borehole and geometrical conditions such as layer-boundary effects and instrument/borehole-related biases. Moreover, conventional multi-mineral analysis rarely includes uncertainty quantification, much less assessing the impact of measurement noise, abnormal borehole conditions, and inaccurate rock-physics models (RPM) on the calculated rock fluid/solid concentrations. The objective of this dissertation is to develop a general probabilistic interpretation method for estimating in situ petrophysical/compositional properties of rocks from well logs and core data. It consists of two sequential Bayesian inversion steps: First, borehole measurements (e.g., density, resistivity, and gamma ray) are “deconvolved” into a layer-by-layer earth model with associated uncertainty via separate well-log inversion. Second, inverted earth-model physical properties are used to estimate volumetric concentrations of fluid and solid rock constituents via petrophysical joint inversion. In each step, Bayesian inversion implements Markov chain Monte Carlo (MCMC) and outputs an ensemble of earth models. Final interpretation results incorporate field-specific a priori knowledge and uncertainty due to measurement noise, instrument/borehole-related biases, and RPM errors. Additionally, a gradient-based MCMC method is introduced for separate well-log inversion to improve the computational efficiency of the probabilistic estimation method. The gradient-based MCMC implements a Gauss-Newton algorithm with Hessian-based sampling to draw samples efficiently from the posterior probability distribution. Compared to the standard random-walk MCMC method, gradient-based MCMC inversion decreases the computational time by more than 90%. A pre-computed surrogate model is also introduced for the rapid calculation of nuclear properties based on radial basis function (RBF) interpolation, which entails ~0.1% of the computational time compared to performing full nuclear-property calculations with less than 0.1% relative error. Finally, the probabilistic inversion method is applied to the interpretation of well logs acquired in multiple neighboring wells. After the mitigation of borehole environmental effects, the inverted earth model is instrument/borehole-independent, allowing a common baseline to effectively compare rock properties across the various wells and detect common rock classes. This procedure also enables the implementation of RPMs and prior compositional models calibrated per rock class to match core laboratory and/or advanced borehole measurements available in a few key wells. The calibrated RPMs and priors are readily implemented in nearby wells penetrating the same rock formations but with a limited number of well logs. The developed multi-well interpretation method is verified using synthetic examples with challenging geological conditions, including thin laminations, significant property contrasts, deep mud-filtrate invasion, complex rock constituents, and various logging instrumental designs (e.g., laterolog vs. induction resistivity). Successful field applications are also documented for the petrophysical interpretation of thinly-laminated shaly sandstones and unconventional organic-shale formations. Results confirm that the probabilistic interpretation method yields more accurate petrophysical estimations compared to the conventional multi-mineral analysis method. Estimated petrophysical and compositional properties and their uncertainty are in good agreement with both core laboratory measurements and interpreted elemental capture spectroscopy logsItem Rock classification from conventional well logs in hydrocarbon-bearing shale(2011-12) Popielski, Andrew Christopher; Torres-Verdín, Carlos; Balhoff, MatthewThis thesis introduces a rock typing method for application in shale gas reservoirs using conventional well logs and core data. Shale gas reservoirs are known to be highly heterogeneous and often require new or modified petrophysical techniques for accurate reservoir evaluation. In the past, petrophysical description of shale gas reservoirs with well logs has been focused to quantifying rock composition and organic-matter concentration. These solutions often require many assumptions and ad-hoc correlations where the interpretation becomes a core matching exercise. Scale effects on measurements are typically neglected in core matching. Rock typing in shale gas provides an alternative description by segmenting the reservoir into petrophysically-similar groups with k-means cluster analysis which can then be used for ranking and detailed analysis of depth zones favorable for production. A synthetic example illustrates the rock typing method for an idealized sequence of beds penetrated by a vertical well. Results and analysis from the synthetic example show that rock types from inverted log properties correctly identify the most organic-rich model types better than rock types detected from well logs in thin beds. Also, estimated kerogen concentration is shown to be most reliable in an under-determined problem. Field cases in the Barnett and Haynesville shale gas plays show the importance of core data for supplementing well logs and identifying correlations for desirable reservoir properties (kerogen/TOC concentration, gas saturation, and porosity). Qualitative rock classes are formed and verified using inverted estimates of kerogen concentration as a rock-quality metric. Inverted log properties identify 40% more of a high-kerogen rock type over well-log based rock types in the Barnett formation. A case in the Haynesville formation suggests the possibility of identifying depositional environments as a result of rock attributes that produce distinct groupings from k-means cluster analysis with well logs. Core data and inversion results indicate homogeneity in the Haynesville formation case. However, the distributions of rock types show a 50% occurrence between two rock types over 90 ft vertical-extent of reservoir. Rock types suggest vertical distributions that exhibit similar rock attributes with characteristic properties (porosity, organic concentration and maturity, and gas saturation). This method does not directly quantify reservoir parameters and would not serve the purpose of quantifying gas-in-place. Rock typing in shale gas with conventional well logs forms qualitative rock classes which can be used to calculate net-to-gross, validate conventional interpretation methods, perform well-to-well correlations, and establish facies distributions for integrated reservoir modeling in hydrocarbon-bearing shale.Item Tool design, physics and interpretation of neutron-gamma density(2016-05) Luycx, Mathilde Michèle; Torres-Verdín, Carlos; Schneider, ErichChemical radioactive sources pose health, safety, and environmental risks. Pulsed neutron generators have replaced Americium/Beryllium sources for the measurement of neutron porosity. However, Cesium 137 (Cs-137) is still mainly used to measure bulk density. Neutron-Gamma density is a new radioisotope-free measurement of density based on neutron-induced inelastic gamma rays. The first part of this report reviews relevant literature to the Neutron-Gamma density measurement and to the modeling of nuclear logging tools. The second part of this report investigates the nuclear physics behind Neutron-Gamma density and presents the development of a tool design optimized for the measurement. The third part of this report regards the development of a real-time interpretation algorithm. The objective of the algorithm is to correct for the changes in spatial distribution and source strength of the neutron-induced gamma ray source. These source variations are caused by fast neutron transport. Therefore, the interpretation algorithm has inputs of fast neutron and gamma ray counts. We achieve an accuracy of 0.019 g/cm3 in clean formation and 0.034 g/cm3 in shale and shaly formations. In the last part of this report, we study some of the measurement limitations regarding the density range and the influence of standoff. The algorithm does not accurately estimate higher densities (densities greater than 2.89 g/cm3) and standoff should be kept to a maximum of 0.25 inch for light mud. Finally, the depth of investigation of Neutron-Gamma Density is twice the depth of investigation of Gamma-Gamma Density. This work is presented as part of the PhD fast track option and will be extended to a PhD dissertation in the future.Item Wettability assessment using resistivity and NMR measurements(2020-02-05) Newgord, Chelsea Lee; Heidari, ZoyaThe wettability of reservoir rocks influences multi-phase fluid flow and rock physics measurements. This impacts the relative permeability, recovery factor, choice of enhanced oil recovery method, and reservoir characterization. Wettability can be assessed using contact angle measurements and the imbibition-based Amott and USBM indices. These methods require preserved core samples, may be time consuming, and cannot be applied for in-situ conditions. Another method to assess wettability is the interpretation of geophysical measurements such as electrical resistivity and Nuclear Magnetic Resonance (NMR). One advantage of geophysical measurements is their applicability for laboratory and in-situ borehole environments. Furthermore, they are quick, non-invasive measurements, and can provide physics-based wettability estimates in near-real-time and in-situ conditions. This thesis provides experimental verification for physics-based assessments of wettability from the interpretation of resistivity and NMR measurements as well as a new workflow for joint interpretation of resistivity and NMR measurements. Recently, analytically-derived resistivity and an NMR-based wettability index rock physics models were introduced and verified using pore-scale simulations. The work presented in this thesis verifies their applicability to core-scale measurements. Additionally, a resistivity-based wettability index is introduced using the fraction of hydrocarbon-wet grains. This index is experimentally verified with Amott and USBM wettability indices. Given reliable estimates of water saturation and the pore-geometry-related model parameters, this resistivity model provides wettability assessment from resistivity measurements with minimal calibration efforts. Moreover, a new method for interpretation of 2D NMR maps is introduced to simultaneously estimate water saturation and wettability. Finally, this thesis introduces an integrated inversion workflow for joint interpretation of resistivity and NMR measurements to simultaneously estimate wettability and water saturation. This method has an average relative error of 11% between the multi-physics- and gravimetric-based water saturation estimates, and an average absolute difference of 0.15 between multi-physics- and Amott wettability indices. This workflow uses physically-meaningful inputs and eliminates the non-uniqueness of water saturation and wettability estimates obtained from independent application of resistivity and NMR models. These outcomes are promising for improved interpretation of resistivity and NMR measurements, particularly in complex, mixed-wet and hydrocarbon-wet formations