A New Multiphysics Method for Simultaneous Assessment of Permeability and Saturation-Dependent Capillary Pressure in Hydrocarbon-Bearing Rocks

SPE Journal ◽  
2020 ◽  
pp. 1-17
Author(s):  
Artur Posenato Garcia ◽  
Zoya Heidari
Keyword(s):  
Pore Structure ◽  
Capillary Pressure ◽  
Size Distribution ◽  
Water Saturation ◽  
Rock Physics ◽  
Rock Fabric ◽  
The Core ◽  
Directional Permeability ◽  
Water Saturated ◽  
Pore Body

Summary Cost-effective exploitation of heterogeneous/anisotropic reservoirs (e.g., carbonate formations) relies on accurate description of pore structure, dynamic petrophysical properties (e.g., directional permeability, saturation-dependent capillary pressure), and fluid distribution. However, techniques for reliable quantification of permeability still rely on model calibration using core measurements. Furthermore, the assessment of saturation-dependent capillary pressure has been limited to experimental measurements, such as mercury injection capillary pressure (MICP). The objectives of this paper include developing a new multiphysics workflow to quantify rock-fabric features (e.g., porosity, tortuosity, and effective throat size) from integrated interpretation of nuclear magnetic resonance (NMR) and electric measurements; introducing rock-physics models that incorporate the quantified rock fabric and partial water/hydrocarbon saturation for assessment of directional permeability and saturation-dependent capillary pressure; and validating the reliability of the new workflow in the core-scale domain. To achieve these objectives, we introduce a new multiphysics workflow integrating NMR and electric measurements, honoring rock fabric, and minimizing calibration efforts. We estimate water saturation from the interpretation of dielectric measurements. Next, we develop a fluid-substitution algorithm to estimate the T2 distribution corresponding to fully water-saturated rocks from the interpretation of NMR measurements. We use the estimated T2 distribution for assessment of porosity, pore-body-size distribution, and effective pore-body size. Then, we develop a new physically meaningful resistivity model and apply it to obtain the constriction factor and, consequently, throat-size distribution from the interpretation of resistivity measurements. We estimate tortuosity from the interpretation of dielectric-permittivity measurements at 960 MHz by applying the concept of capacitive formation factor. Finally, throat-size distribution, porosity, and tortuosity are used to calculate directional permeability and saturation-dependent capillary pressure. We test the reliability of the new multiphysics workflow in the core-scale domain on rock samples at different water-saturation levels. The introduced multiphysics workflow provides accurate description of the pore structure in partially water-saturated formations with complex pore structure. Moreover, this new method enables real-time well-log-based assessment of saturation-dependent capillary pressure and directional permeability (in presence of directional electrical measurements) in reservoir conditions, which was not possible before. Quantification of capillary pressure has been limited to measurements in laboratory conditions, where the differences in stress field reduce the accuracy of the estimates. We verified that the estimates of permeability, saturation-dependent capillary pressure, and throat-size distribution obtained from the application of the new workflow agreed with those experimentally determined from core samples. We selected core samples from four different rock types, namely Edwards Yellow Limestone, Lueders Limestone, Berea Sandstone, and Texas Cream Limestone. Finally, because the new workflow relies on fundamental rock-physics principles, permeability and saturation-dependent capillary pressure can be estimated from well logs with minimum calibration efforts, which is another unique contribution of this work.

scholarly journals Construction of pore structure and lithology of digital rock physics based on laboratory experiments

2021 ◽  
Vol 11 (5) ◽  
pp. 2113-2125
Author(s):  
Chenzhi Huang ◽  
Xingde Zhang ◽  
Shuang Liu ◽  
Nianyin Li ◽  
Jia Kang ◽  
...  
Keyword(s):  
Pore Structure ◽  
Pore Size Distribution ◽  
Pore Size ◽  
Size Distribution ◽  
Laboratory Experiments ◽  
Rock Physics ◽  
Reconstruction Method ◽  
Digital Rock Physics ◽  
Digital Rock ◽  
The Core

AbstractThe development and stimulation of oil and gas fields are inseparable from the experimental analysis of reservoir rocks. Large number of experiments, poor reservoir properties and thin reservoir thickness will lead to insufficient number of cores, which restricts the experimental evaluation effect of cores. Digital rock physics (DRP) can solve these problems well. This paper presents a rapid, simple, and practical method to establish the pore structure and lithology of DRP based on laboratory experiments. First, a core is scanned by computed tomography (CT) scanning technology, and filtering back-projection reconstruction method is used to test the core visualization. Subsequently, three-dimensional median filtering technology is used to eliminate noise signals after scanning, and the maximum interclass variance method is used to segment the rock skeleton and pore. Based on X-ray diffraction technology, the distribution of minerals in the rock core is studied by combining the processed CT scan data. The core pore size distribution is analyzed by the mercury intrusion method, and the core pore size distribution with spatial correlation is constructed by the kriging interpolation method. Based on the analysis of the core particle-size distribution by the screening method, the shape of the rock particle is assumed to be a more practical irregular polyhedron; considering this shape and the mineral distribution, the DRP pore structure and lithology are finally established. The DRP porosity calculated by MATLAB software is 32.4%, and the core porosity measured in a nuclear magnetic resonance experiment is 29.9%; thus, the accuracy of the model is validated. Further, the method of simulating the process of physical and chemical changes by using the digital core is proposed for further study.

A Three-Phase Study on Preflush Stage in Sandstone Acidizing: Experimental and Modeling Analysis of Evolved Carbon Dioxide in a Hydrocarbon and Aqueous Environment

SPE Journal ◽  
2020 ◽  
pp. 1-26
Author(s):  
Sajjaat Muhemmed ◽  
Harish Kumar ◽  
Nicklaus Cairns ◽  
Hisham A. Nasr-El-Din
Keyword(s):  
Carbon Dioxide ◽  
Water Saturation ◽  
Injection Rate ◽  
Mineral Dissolution ◽  
Carbonate Mineral ◽  
Carbonate Minerals ◽  
Oil Saturation ◽  
The Core ◽  
Three Phase ◽  
Water Saturated

Summary Limited studies have been conducted in understanding the mechanics of preflush stages in sandstone-acidizing processes. Among those conducted in this area, all efforts have been directed toward singular aqueous-phase scenarios. Encountering 100% water saturation (Sw) in the near-wellbore region is seldom the case because hydrocarbons at residual or higher saturations can exist. Carbonate-mineral dissolution, being the primary objective of the preflush stage, results in carbon dioxide (CO2) evolution. This can lead to a multiphase presence depending on the conditions in the porous medium, and this factor has been unaccounted for in previous studies under the assumption that all the evolved CO2 is dissolved in the surrounding solutions. The performance of a preflush stage changes in the presence of multiphase environments in the porous media. A detailed study is presented on the effects of evolved CO2 caused by carbonate-mineral dissolution, and its ensuing activity during the preflush stages in matrix acidizing of sandstone reservoirs. Four Carbon Tan Sandstone cores were used toward the purpose of this study, of which two were fully water saturated and the remaining two were brought to initial water saturation (Swi) and residual oil saturation to waterfloods (Sorw) before conducting preflush-stage experiments. The preflush-stage fluid, 15 wt% hydrochloric acid (HCl), was injected in the concerning cores while maintaining initial pore pressures of 1,200 psi and constant temperatures of 150°F. A three-phase-flow numerical-simulation model coupled with chemical-reaction and structure-property modeling features is used to validate the conducted preflush-stage coreflood experiments. Initially, the cores are scanned using computed tomography (CT) to accurately characterize the initial porosity distributions across the cores. The carbonate minerals present in the cores, namely calcite and dolomite, are quantified experimentally using X-ray diffraction (XRD). These measured porosity distributions and mineral concentrations are populated across the core-representative models. The coreflood effluents’ calcium chloride and magnesium chloride, which are acid/carbonate-mineral-reaction products, as well as spent-HCl concentrations were measured. The pressure drop across the cores was logged during the tests. These parameters from all the conducted coreflood tests were used for history matching using the numerical model. The calibrated numerical model was then used to understand the physics involved in this complex subsurface process. In fully water-saturated cores, a major fraction of unreacted carbonate minerals still existed even after 40 pore volumes (PV) of preflush acid injection. Heterogeneity is induced as carbonate-mineral dissolution progresses within the core, creating paths of least resistance, leading to the preferential flow of the incoming fresh acid. This leads to regions of carbonate minerals being untouched during the preflush stimulation stage. A power-law trend, P = aQb, is observed between the stabilized pressure drops at each sequential acid-injection rate vs. the injection rates, where P is the pressure drop across the core, Q is the sequential flow rate, and a and b are constants, with b < 1. An ideal maximum injection rate can be deduced to optimize the preflush stage toward efficient carbonate-mineral dissolution in the damaged zone. An average of 25% recovery of the oil in place (OIP) was seen from preflush experiments conducted on cores with Sorw. In cores with Swi, the oil saturation was reduced during the preflush stage to a similar value as in the cores with Sorw. The oil-phase-viscosity reduction caused by CO2 dissolution in oil and the increase in saturation and permeability to the oil phase resulting from oil swelling by CO2 are inferred as the main mechanisms for any additional oil production beyond residual conditions during the preflush stage. The potential of evolved CO2, a byproduct of the sandstone-acidizing preflush stage, toward its contribution in swelling the surrounding oil, lowering its viscosity, and thus mobilizing the trapped oil has been depicted in this study

Whole Core Analysis - Experience and Challenges

2005 ◽  
Vol 8 (06) ◽  
pp. 460-469 ◽  
Author(s):  
Mehdi M. Honarpour ◽  
Nizar F. Djabbarah ◽  
Krishnaswamy Sampath
Keyword(s):  
Electrical Properties ◽  
Capillary Pressure ◽  
Carbonate Rocks ◽  
Water Saturation ◽  
Core Analysis ◽  
Confining Stress ◽  
X Ray ◽  
X Ray Imaging ◽  
Directional Permeability ◽  
Special Core Analysis

Summary Whole-core analysis is critical for characterizing directional permeability in heterogeneous, fractured, and/or anisotropic rocks. Whole-core measurements are essential for heterogeneous reservoirs because small-scale heterogeneity may not be appropriately represented in plug measurements. For characterization of multiphase-flow properties (special core analysis) in heterogeneous rocks, whole-core analysis is also required. Few commercial laboratories are equipped to conduct routine measurements on whole cores up to 4 in. in diameter and up to 8 in. long and, importantly, under simulated reservoir net confining stress (NCS). Special whole-core analyses are rarely conducted because of the difficulties associated with establishing a representative water saturation in drainage capillary pressure experiments and measuring directional effective permeabilities. Electrical properties also can be measured on whole cores to determine porosity and saturation exponents for situations in which resistivity tools are used in horizontal or highly deviated wells. In this paper, we provide an overview of routine and special core-analysis measurements on whole cores. Results from selected heterogeneous sandstone and carbonate rocks will be discussed. We also will show how the results relate to data obtained from plug analysis, with particular emphasis on directional absolute permeability, trapped-gas and fluid saturations, and the effect of NCS. Finally, we will describe a novel apparatus for special core analysis on whole cores and provide examples of the capabilities of the system. In this paper, we will present:• Recommended techniques for the determination of directional absolute and effective permeability and for establishing initial water saturation in whole cores.• Improved understanding of the effect of scale (sample size) on the measured properties.• Description of a novel whole-core apparatus with measurement of fluid-saturation distribution using in-situ saturation monitoring. Introduction Reservoir rocks are heterogeneous, especially carbonate rocks, in which more than 50% of the world's hydrocarbon reserves are deposited. Fig. 1 shows an example of variability in rock characteristics as observed in a carbonate-rockout crop in Oman. The heterogeneous nature of these rocks tends to become more apparent as attempts are made to measure their petrophyscal properties at various scales. An example of permeability variation in a plug from a carbonate formation is shown in Fig. 2. Single-phase air permeability varies by three orders of magnitude over the distance of a few centimeters in this core plug. This dual-porosity behavior impacts the spontaneous-imbibition performance significantly (Fig. 3). Technology at Commercial Laboratories Selected commercial laboratories have capabilities to appropriately clean and prepare whole cores, perform core X-ray imaging, and measure basic properties such as directional permeability and porosity under a maximum confining stress of 5,000 psi. Available technologies for imaging, sample preparation, and routine core analysis are summarized in the following sections. Special-core-analysis capabilities at commercial laboratories are rare. Only one or two laboratories are capable of measuring primary-drainage gas/water capillary pressure and gas/water or oil/water electrical properties on whole cores at confining stress. Whole-Core Imaging and Screening Whole-core photography and X-ray imaging provide information about surface features and internal structure. The computed tomography (CT) scan provides evidence of fractures, vugs, and heterogeneities as indicated by the extent in the variation of CT density. X-ray fluoroscopy and CT are two of the most practical X-ray scanning techniques used to characterize core-level heterogenieties and to explain their effect on horizontal and vertical permeabilities. CT-scanning algorithms should often be modified to obtain images free of artifacts and with better than0.5-mm horizontal and 1-mm vertical resolutions.

scholarly journals Predicting the Relative Permeability of Water Phase Based on Theory of Coupled Electricity-Seepage and Capillary Bundle Model

2015 ◽  
Vol 8 (1) ◽  
pp. 344-349 ◽  
Author(s):  
Xinmin Ge ◽  
Yiren Fan ◽  
Donghui Xing ◽  
Jingying Chen ◽  
Yunhai Cong ◽  
...  
Keyword(s):  
Fractal Dimension ◽  
Pore Structure ◽  
Capillary Pressure ◽  
Relative Permeability ◽  
Water Saturation ◽  
Saturation Index ◽  
Dynamic Parameters ◽  
Empirical Formulas ◽  
Capillary Bundle ◽  
Capillary Walls

An analytical water relative model based on the theory of coupled electricity-seepage and capillary bundle pore structure is described. The model shows that the relative permeability of water is affected by two kinds of parameters, which are depicted as static parameters and dynamic parameters. Revised Kozeny-Carman equation and Archie formulas are introduced to deduce the model, which enhance the characterization ability of pore structure. Two displacing states, where we summarized that oil coats capillary walls and oil occupies capillary centers are also discussed for optimization of the model. In contrast to existing empirical formulas where relative permeability is strongly related to capillary pressure and fractal dimension, we introduce only water saturation and saturation index as input parameters, which make the model simpler to use. Petrophysics and unsteady relative permeability experiments (oil displacing water) are carried out to testify the two models. The fitting results show that for oil displacing experiments presented in this paper, the displacing state where oil coats capillary walls is suitable to predict the relative permeability of water.

APPLICATION OF RESISTIVITY INVERSION MODELLING TO ENHANCE WATER SATURATION CALCULATIONS FROM WIRELINE LOGS

2000 ◽  
Vol 40 (1) ◽  
pp. 355
Author(s):  
C.J. Shield
Keyword(s):  
Capillary Pressure ◽  
Water Saturation ◽  
Strong Relationship ◽  
Data Set ◽  
Hydrocarbon Reservoir ◽  
The Core ◽  
Irreducible Water Saturation ◽  
Resistivity Logs ◽  
Resistivity Inversion ◽  
Induction Logs

Water saturation (Sw) values calculated from resistivity or induction logs are often higher than those measured from core-derived capillary pressure (Pc) measurements. The core-derived Sw measurements are commonly applied for reservoir simulation in preference to the log-derived Sw calculations. As it is economically and logistically impractical to core every hydrocarbon reservoir, a method of correlating the core-derived Sw to resistivity/induction logs is required. Two-dimensional resistivity modelling is applied to dual laterolog data to ascertain the applicability of this technique.The Griffin and Scindian/Chinook Fields, offshore Western Australia, have been producing hydrocarbons since 1994 from two early-to-middle Cretaceous reservoirs, the clean quartzose sandstones of the Zeepaard Formation and the overlying glauconitic, quartzose sandstones of the Birdrong Formation. Routine and special core analysis of cores recovered from wells intersecting these two reservoirs creates an excellent data set with which to correlate the good quality wireline log data.A strong relationship is noted between the modelled water saturation from resistivity logs, and the irreducible water saturation measured from core capillary pressure data. Correlation between the core-derived permeability and the invasion diameter calculated from the modelled laterolog data is shown to produce a locally applicable means of estimating permeability from the resistivity modelling results.The evaluation of these data from the Griffin and Scindian/Chinook Fields provides a method for reducing appraisal and development well analysis costs, through the closer integration of core and wireline log data at an earlier stage of the field appraisal phase.

Effects of pore structure and wettability on the electrical resistivity of partially saturated rocks—A network study

Geophysics ◽  
1997 ◽  
Vol 62 (4) ◽  
pp. 1151-1162 ◽  
Author(s):  
Ravi J. Suman ◽  
Rosemary J. Knight
Keyword(s):  
Pore Structure ◽  
Pore Size Distribution ◽  
Pore Size ◽  
Size Distribution ◽  
Network Model ◽  
Water Saturation ◽  
Archie’S Law ◽  
Partially Saturated ◽  
Saturation Exponent ◽  
Wetting Film

A network model of porous media is used to assess the effects of pore structure and matrix wettability on the resistivity of partially saturated rocks. Our focus is the magnitude of the saturation exponent n from Archie's law and the hysteresis in resistivity between drainage and imbibition cycles. Wettability is found to have the dominant effect on resistivity. The network model is used to investigate the role of a wetting film in water‐wet systems, and the behavior of oil‐wet systems. In the presence of a thin wetting film in water‐wet systems, the observed variation in n with saturation is reduced significantly resulting in lower n values and reduced hysteresis. This is attributed to the electrical continuity provided by the film at low‐water saturation between otherwise physically isolated portions of water. Oil‐wet systems, when compared with the water‐wet systems, are found to have higher n values. In addition, the oil‐wet systems exhibit a different form of hysteresis and more pronounced hysteresis. These differences in the resistivity response are attributed to differences in the pore scale distribution of water. The effects of pore structure are assessed by varying pore size distribution and standard deviation of the pore size distribution and considering networks with pore size correlation. The most significant parameter is found to be the pore size correlation. When the sizes of the neighboring pores of the network are correlated positively, the magnitude of n and hysteresis are reduced substantially in both the water‐wet and oil‐wet systems. This is attributed to higher pore accessibility in the correlated networks. The results of the present study emphasize the importance of conducting laboratory measurements on core samples with reservoir fluids and wettability that is representative of the reservoir. Hysteresis in resistivity can be present, particularly in oil‐wet systems, and should be considered in the interpretation of resistivity data.

Assessment of Water Saturation Using Dielectric Permittivity Measurements in Formations with Complex Pore Structure: Application to the Core- and Log- Scale Domains

2021 ◽  
Author(s):  
Zulkuf Azizoglu ◽  
Zoya Heidari ◽  
Leonardo Goncalves ◽  
Lucas Abreu Blanes De Oliveira ◽  
Moacyr Silva Do Nascimento Neto
Keyword(s):  
Dielectric Permittivity ◽  
Pore Structure ◽  
Water Saturation ◽  
Rock Type ◽  
Dielectric Dispersion ◽  
Well Logs ◽  
Well Log ◽  
Dielectric Measurements ◽  
The Core ◽  
Permittivity Measurements

Abstract Broadband dielectric dispersion measurements are attractive options for assessment of water-filled pore volume, especially when quantifying salt concentration is challenging. However, conventional models for interpretation of dielectric measurements such as Complex Refractive Index Model (CRIM) and Maxwell Garnett (MG) model require oversimplifying assumptions about pore structure and distribution of constituting fluids/minerals. Therefore, dielectric-based estimates of water saturation are often not reliable in the presence of complex pore structure, rock composition, and rock fabric (i.e., spatial distribution of solid/fluid components). The objectives of this paper are (a) to propose a simple workflow for interpretation of dielectric permittivity measurements in log-scale domain, which takes the impacts of complex pore geometry and distribution of minerals into account, (b) to experimentally verify the reliability of the introduced workflow in the core-scale domain, and (c) to apply the introduced workflow for well-log-based assessment of water saturation. The dielectric permittivity model includes tortuosity-dependent parameters to honor the complexity of the pore structure and rock fabric for interpretation of broadband dielectric dispersion measurements. We estimate tortuosity-dependent parameters for each rock type from dielectric permittivity measurements conducted on core samples. To verify the reliability of dielectric-based water saturation model, we conduct experimental measurements on core plugs taken from a carbonate formation with complex pore structures. We also introduce a workflow for applying the introduced model to dielectric dispersion well logs for depth-by-depth assessment of water saturation. The tortuosity-dependent parameters in log-scale domain can be estimated either via experimental core-scale calibration, well logs in fully water-saturated zones, or pore-scale evaluation in each rock type. The first approach is adopted in this paper. We successfully applied the introduced model on core samples and well logs from a pre-salt formation in Santos Basin. In the core-scale domain, the estimated water saturation using the introduced model resulted in an average relative error of less than 11% (compared to gravimetric measurements). The introduced workflow improved water saturation estimates by 91% compared to CRIM. Results confirmed the reliability of the new dielectric model. In application to well logs, we observed significant improvements in water saturation estimates compared to cases where a conventional effective medium model (i.e., CRIM) was used. The documented results from both core-scale and well-log-scale applications of the introduced method emphasize on the importance of honoring pore structure in the interpretation of dielectric measurements.

scholarly journals Analysis of the efficiency of models of transition zones to determine oil-saturation factors and position of contact of hydrocarbons with water

2020 ◽  
pp. 67-76
Author(s):  
G. E. Stroyanetskaya
Keyword(s):  
Capillary Pressure ◽  
Transition Zone ◽  
Water Saturation ◽  
Residual Water ◽  
Oil Saturation ◽  
Transition Zones ◽  
The Core ◽  
Geophysical Parameter ◽  
Saturation Factor ◽  
Geophysical Information

The article is devoted to the usage of models of transition zones in the interpretation of geological and geophysical information. These models are graphs of the dependences of oil-saturation factors of the collectors on their height above the level with zero capillary pressure, taking into account the geological and geophysical parameter. These models are not recommended for estimating oilsaturation factors of collectors in the transition zone. The height of occurrence of the collector above the level of zero capillary pressure can be estimated from model of the transition zone that take into account the values of the coefficients of residual water saturation factor of the collectors, but only when the model of the transition zone is confirmed by data capillarimetry studies on the core.

scholarly journals Permeability and Rock Fabric from Wireline Logs, Arab-D Reservoir, Ghawar Field, Saudi Arabia

GeoArabia ◽  
2001 ◽  
Vol 6 (4) ◽  
pp. 619-646
Author(s):  
F. Jerry Lucia ◽  
James W. Jennings ◽  
Michael Rahnis ◽  
Franz O. Meyer
Keyword(s):  
Pore Size Distribution ◽  
Pore Size ◽  
Size Distribution ◽  
Spatial Information ◽  
Water Saturation ◽  
Reservoir Rock ◽  
Petrophysical Properties ◽  
Rock Fabric ◽  
Interparticle Porosity ◽  
Wireline Logs

ABSTRACT The goal of reservoir characterization is to distribute petrophysical properties in 3-D. Porosity, permeability, and saturation values have no intrinsic spatial information and must be linked to a 3-D geologic model to be distributed in space. This link is provided by relating petrophysical properties to rock fabrics. The vertical succession of rock fabrics was shown to be useful in constructing a geologic framework for distributing porosity, permeability, and saturation in 3-D. Permeability is perhaps the most difficult petrophysical property to obtain and image because its calculation from wireline logs requires the estimation of pore-size distribution. In this study of the Arab-D reservoir, rock fabric and interparticle porosity were used to estimate pore-size distribution. Cross-plots of water saturation and porosity, calibrated with rock-fabric descriptions, formed the basis for determining the distribution of rock fabric and pore size from resistivity and porosity logs. Interparticle porosity was obtained from travel-time/porosity, cross-plot relationships. A global porosity-permeability transform that related rock fabric, interparticle porosity, and permeability was the basis for calculating permeability from wireline logs. Calculated permeability values compared well with core permeability. In uncored wells, permeability was summed vertically and the horizontal permeability profile compared with flow-meter data. The results showed good correlation in most wells.

EXPERIENCE WITH DETERMINATION OF WATER SATURATION FROM CORE IN THE COSSACK FIELD

1993 ◽  
Vol 33 (1) ◽  
pp. 39
Author(s):  
D. Lasserre & C.F. Choo
Keyword(s):  
Capillary Pressure ◽  
Water Saturation ◽  
Pressure Data ◽  
Reservoir Rocks ◽  
Saturation Parameter ◽  
The Core ◽  
Sandstone Reservoir

Water saturation measurements were made on core in two Cossack field appraisal wells to investigate the discrepancy between the water saturation calculated from logs and that observed from the capillary pressure data in the Cossack-1 discovery well. The core measurements resulted in a more accurate water saturation parameter which was then used to estimate the volume of hydrocarbons in place. The core measurements also provided valuable information about the wettability of the reservoir rocks. The results of this exercise also highlighted the uncertainty attached to the water saturation determination from logs in what was an apparently simple case of a thick, clean sandstone reservoir.

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