This thesis introduces a workflow to accomplish invasion-consistent Nuclear Magnetic Resonance (NMR) measurement interpretations. Magnetic resonance measurements are affected by mud-filtrate invasion because the radial depth of investigation (DOI) of NMR logging tools is very shallow (approximately 1 to 4 inches). This characteristic indicates that identification of in-situ fluid saturations from NMR measurements is uncertain. Calculation of fluid saturations from apparent electrical resistivities and nuclear logs does not guarantee a precise estimation of the fluid distributions. Free water in the reservoir displaced by oil based mud (OBM) poses more challenges in the estimation of in-situ fluid saturations. To mitigate this ambiguity, I construct layer-by-layer static and dynamic reservoir models. The common stratigraphic framework (CSF) proposed by Voss et al. (2009) was used to construct the earth model. Appraisal of static petrophysical properties is based on the iterative adjustments to minimize the discrepancy between available well logs and their numerical simulations. Evaluation of dynamic petrophysical properties can be achieved with the simulation of mud-filtrate invasion. This simulation can assess accurate fluid saturations at specific radial distances. In addition, numerically simulated apparent resistivity and nuclear logs are in agreement with measured logs. Algorithms are also developed to cross-validate NMR measurements based on the assumption of spherically shaped water-wet pores. The algorithms need all petrophysical parameters and fluid saturations yielded from the dynamic model as inputs. Various NMR parameter changes were tested to validate this algorithm. Examples of NMR responses include wettability change and kerogen contained in nano-scale pores. For the field case examples, two 15 meter-thick depth intervals in oil- and gas-bearing siliciclastic formations were selected. Two-dimensional (2D) NMR simulations were performed with petrophysical parameters provided from the numerical simulation of mud-filtrate invasion. The 2D NMR maps are more favorable in fluid typing than conventional NMR T₂ distributions because they contrast fluid diffusion coefficient. Comparisons of simulation results to inversion results confirm the validity of the workflow introduced in this thesis for the quantification of virgin reservoir fluids and mud-filtrate saturations. Finally, forward modeling and inversion processes are applied to 2D NMR data. The reconstructed echo decay sequences are more advantageous than raw measurements because of their higher signal to noise ratio (SNR). Linear inversion using these echo decay sequences provides proton density distribution functions of D-T₂ and T₁-T₂ maps. Application of inversion to the two field cases measured from two different radial depths verifies the validity of the NMR interpretations. / text

Nuclear magnetic resonance (NMR) has become an effective borehole measurement option to assess petrophysical and fluid properties of porous and permeable rocks. In the case of fluid typing, two-dimensional (2D) NMR interpretation techniques have advantages over conventional one-dimensional (1D) interpretation as they provide additional discriminatory information about saturating fluids and their properties. However, often there is ambiguity as to whether fluids detected with NMR measurements are mobile or residual. In some instances, rapid vertical variations of rock properties (e.g. across thinly-bedded formations) can make it difficult to separate NMR fluid signatures from those due to pore-size distributions. There are also cases where conventional fluid identification methods based on resistivity and nuclear logs indicate dominant presence of water while NMR measurements indicate presence of water, hydrocarbon, and mud filtrate. In such cases, it is important to ascertain whether existing hydrocarbons are residual or mobile. The radial lengths of investigation of resistivity, nuclear, and NMR measurements are very different, with NMR measurements being the shallowest sensing. Even in the case of several radial zones of NMR response attributed to different acquisition frequencies and DC magnetic field gradients, the measured signal originates from a fairly shallow radial zone compared to that of nuclear and resistivity logs. Depending on drilling mud being used and the radial extent of mud-filtrate invasion, the NMR response of virgin reservoir fluids can be masked by mud filtrate because of fluid displacement and mixing. In order to separate those effects, it is important to reconcile NMR measurements with electrical and nuclear logs for improved assessment of porosity and mobile hydrocarbon saturation. Previously, Voss et al. (2009) and Gandhi et al. (2010) introduced the concept of Common Stratigraphic Framework (CSF) to construct and validate multi-layer static and dynamic petrophysical models based on the numerical simulation of well logs. In this thesis, the concept of CSF is implemented to reconcile 2D NMR interpretations with multi-layer static and dynamic petrophysical models. It is found that quantifying the exact radial zone of response and corresponding fluid saturations can only be accomplished with studies of mud-filtrate invasion that honor available resistivity and nuclear logs. This thesis indicates that the two interpretation methods complement each other and when applied in conjunction, improve and refine the overall petrophysical understanding of permeable rock formations. Examples of successful application include field data acquired in thinly-bedded gas formations invaded with water-base mud, where bed-boundary effects are significant and residual hydrocarbon saturation is relatively high. In such cases, numerical simulation of mud-filtrate invasion and well logs acquired after invasion enables reliable interpretations of petrophysical and fluid properties. The interpretation procedure introduced in this thesis also provides an explicit way to determine the uncertainty of petrophysical and fluid interpretations. / text

Estimation of static and dynamic petrophysical properties of multi-layer hydrocarbon reservoirs is crucial for the assessment of storage and flow capacities, compartmentalization, and for best primary or enhanced recovery practices. Interactive numerical simulation to reproduce field logs and core data is a reliable procedure to estimate static and dynamic petrophysical properties of complex rock formations. Previously, Voss et al. (2009) introduced the concept of Common Stratigraphic Framework (CSF) to construct and cross-validate multi-layer static/dynamic petrophysical models by invoking the interactive, numerical simulation of well logs both before and after invasion. This thesis documents the successful implementation of the CSF concept to examine and quantify the effects of mud-filtrate invasion on apparent resistivity, nuclear, and magnetic resonance logs acquired in San Martin, Cashiriari and Pagoreni gas fields in Camisea, Peru. Conventional petrophysical interpretation methods yield abnormally high estimates of water saturation in some of the reservoir units that produce gas with null water influx. This anomalous behavior is due to relatively low values of deep apparent electrical resistivity, and has otherwise been attributed to the presence of clay-coating grains and/or electrically conductive grain minerals. On the other hand, electrical resistivity logs exhibit substantial invasion effects as evidenced by the separation of apparent resistivity logs (both LWD and wireline) with multiple radial lengths of investigation. In extreme cases, apparent resistivity logs “stack” because of very deep invasion. We diagnose and quantify invasion effects on resistivity and nuclear logs with interactive numerical modeling before and after invasion. The assimilation of such effects in the interpretation consistently decreases previous estimates of water saturation to those of irreducible water saturation inferred from core data. It is shown that capillary pressure effects are responsible for the difference in separation of resistivity curves in some of the reservoir units. The final multi-layer CSF is in agreement with gas production measurements and permits reliable flow predictions to assist in reservoir engineering and production studies. / 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

Well logs and formation testers are routinely used for detection and quantification of hydrocarbon reserves. Overbalanced drilling causes invasion of mud filtrate into permeable rocks, hence radial displacement of in-situ saturating fluids away from the wellbore. The spatial distribution of fluids in the near-wellbore region remains affected by a multitude of petrophysical and fluid factors originating from the process of mud-filtrate invasion. Consequently, depending on the type of drilling mud (e.g. water- and oil-base muds) and the influence of mud filtrate, well logs and formation-tester measurements are sensitive to a combination of in-situ (original) fluids and mud filtrate in addition to petrophysical properties of the invaded formations. This behavior can often impair the reliable assessment of hydrocarbon saturation and formation storage/mobility. The effect of mud-filtrate invasion on well logs and formation-tester measurements acquired in vertical wells has been extensively documented in the past. Much work is still needed to understand and quantify the influence of mud-filtrate invasion on well logs acquired in horizontal and deviated wells, where the spatial distribution of fluids in the near-wellbore region is not axial-symmetric in general, and can be appreciably affected by gravity segregation, permeability anisotropy, capillary pressure, and flow barriers. This dissertation develops a general algorithm to simulate the process of mud-filtrate invasion in vertical and deviated wells for drilling conditions that involve water- and oil-base mud. The algorithm is formulated in cylindrical coordinates to take advantage of the geometrical embedding imposed by the wellbore in the spatial distribution of fluids within invaded formations. In addition, the algorithm reproduces the formation of mudcake due to invasion in permeable formations and allows the simulation of pressure and fractional flow-rate measurements acquired with dual-packer and point-probe formation testers after the onset of invasion. An equation-of-state (EOS) formulation is invoked to simulate invasion with both water- and oil-base muds into rock formations saturated with water, oil, gas, or stable combinations of the three fluids. The algorithm also allows the simulation of physical dispersion, fluid miscibility, and wettability alteration. Discretized fluid flow equations are solved with an implicit pressure and explicit concentration (IMPEC) scheme. Thermodynamic equilibrium and mass balance, together with volume constraint equations govern the time-space evolution of molar and fluid-phase concentrations. Calculations of pressure-volume-temperature (PVT) properties of the hydrocarbon phase are performed with Peng-Robinson's equation of state. A full-tensor permeability formulation is implemented with mass balance equations to accurately model fluid flow behavior in horizontal and deviated wells. The simulator is rigorously and successfully verified with both analytical solutions and commercial simulators. Numerical simulations performed over a wide range of fluid and petrophysical conditions confirm the strong influence that well deviation angle can have on the spatial distribution of fluid saturation resulting from invasion, especially in the vicinity of flow barriers. Analysis on the effect of physical dispersion on the radial distribution of salt concentration shows that electrical resistivity logs could be greatly affected by salt dispersivity when the invading fluid has lower salinity than in-situ water. The effect of emulsifiers and oil-wetting agents present in oil-base mud was studied to quantify wettability alteration and changes in residual water saturation. It was found that wettability alteration releases a fraction of otherwise irreducible water during invasion and this causes electrical resistivity logs to exhibit an abnormal trend from shallow- to deep-sensing apparent resistivity. Simulation of formation-tester measurements acquired in deviated wells indicates that (i) invasion increases the pressure drop during both drawdown and buildup regimes, (ii) bed-boundary effects increase as the wellbore deviation angle increases, and (iii) a probe facing upward around the perimeter of the wellbore achieves the fastest fluid clean-up when the density of invading fluid is larger than that of in-situ fluid. / text