Neutron Porosity Logs Research Articles

A combined Parzen-wavelet approach for detection of vuggy zones in fractured carbonate reservoirs using petrophysical logs

Abstract Vuggy porosity which is the most important type of porosity in carbonate rocks, significantly affects permeability, pressure drop and recovery factor of the rocks. As a result, its identification and modeling are essential for reservoir characterization and history matching. Image logs as well as RCAL and SCAL tests are main methods to determine vugs. However, these methods are costly and usually unavailable. Therefore, developing a generalized approach for recognizing vugs appears to be necessary. In this paper, a combined Parzen-wavelet based algorithm is developed for identifying vuggy zones in wavelet coefficient domain using gamma ray (GR), neutron porosity (NPHI), bulk density (RHOB) and sonic (DT) logs. Compatibility between core tests and the results of the developed method revealed the capability of the method.

Improvements in crosshole GPR full-waveform inversion and application on data measured at the Boise Hydrogeophysics Research Site

Abstract Crosshole ground penetrating radar (GPR) tomography has been widely used and has the potential to improve the obtained subsurface models due to its high spatial resolution compared to other methods. Recent advances in full-waveform inversion of crosshole GPR data show that higher resolution images can be obtained compared to conventional ray-based GPR inversion because it can exploit all information present in the observed data. Since the first application of full-waveform inversion on synthetic and experimental GPR data, the algorithm has been significantly improved by extending the scalar to a vectorial approach, and changing the stepped permittivity and conductivity update into a simultaneous update. Here, we introduce new normalized gradients that do not depend on the number of sources and receivers which enable a comparison of the gradients and step lengths for different crosshole survey layouts. An experimental data set acquired at the Boise Hydrogeophysics Research Site is inverted using different source–receiver setups and the obtained permittivity and conductivity images, remaining gradients and final misfits are compared for the different versions of the full-waveform inversion. Moreover, different versions of the full-waveform inversion are applied to obtain an overview of all improvements. Most improvements result in a reducing final misfit between the measured and synthetic data and a reducing remaining gradient at the final iteration. Regions with relatively high remaining gradient amplitudes indicate less reliable inversion results. Comparison of the final full-waveform inversion results with Neutron–Neutron porosity log data and capacitive resistivity log data show considerably higher spatial frequencies for the logging data compared to the full-waveform inversion results. To enable a better comparison, we estimated a simple wavenumber filter and the full-waveform inversion results show an improved fit with the logging data. This work shows the potential of full-waveform inversion as an advanced method that can provide high resolution images to improve hydrological models.

Gardner's Relationship and Regression Analysis for Prediction of P-Wave Velocity; Case Study, Fractured Dolomitic Limestone Reservoir, Farour.A Oil Field, Persian Gulf, Iran

In many cases, velocity information is unavailable while it is essential for some processes such as making synthetic seismogram. Gardner et al.'s (1974) relationship is such a good approximation of velocity by using density information, but it is a general relationship and in this case for a fractured dolomitic limestone gas reservoir it was less effective. Cross plot analysis and cross validation error were performed and bulk density and neutron porosity logs were selected as the most related to sonic velocity log. So, by using regression analysis, Gardner et al.'s relationship coefficients modified and three new formulas obtained and error and uncertainty reduced significantly.

Fast modeling of borehole neutron porosity measurements with a new spatial transport-diffusion approximation

The quantitative integration of nuclear measurements into the in situ petrophysical and geophysical evaluation of rock formations has been elusive because of the lack of efficient algorithms to simulate them. We discovered a new method for rapid numerical simulation of borehole neutron measurements using Monte Carlo (MC)-derived spatial flux sensitivity functions (FSFs) and diffusion flux-difference (DFD) approximations. The method calculates spatial sensitivity flux perturbations using flux-difference approximations of one-group neutron diffusion models. By invoking appropriate boundary conditions, the one-group, time-independent neutron diffusion solution is implemented for nonmultiplying systems in 2D and 3D cylindrical coordinates. The solution is differentiated with respect to the neutron cross section to obtain an expression for flux-difference due to cross-section perturbations. Constant transport-correction coefficients for cross-section parameters are calculated with a flux-fitting method to account for deviations of borehole neutron measurements from the physics of diffusion. Thereafter, spatial FSF responses are rapidly and accurately calculated using a first-order Rytov DFD approximation. Estimated flux-differences are next used to calculate lumped higher order perturbation terms. The DFD technique is tested and benchmarked against MC calculations in the presence of standoff, invasion, and well deviation for wireline and logging-while-drilling tools. Benchmark examples and application in highly deviated wells indicate that neutron porosity logs can be accurately and efficiently simulated with the new DFD method, even in complex geometrical and physical conditions, with errors lower than 1.2 porosity units.

Facies recognition using a smoothing process through Fast Independent Component Analysis and Discrete Cosine Transform

We propose a preprocessing methodology for well-log geophysical data based on Fast Independent Component Analysis (FastICA) and Discrete Cosine Transform (DCT), in order to improve the success rate of the K-NN automatic classifier. The K-NN have been commonly applied to facies recognition in well-log geophysical data for hydrocarbon reservoir modeling and characterization.The preprocess was made in two different levels. In the first level, a FastICA based dimenstion reduction was applied, maintaining much of the information, and its results were classified; In second level, FastICA and DCT were applied in smoothing level, where the data points are modified, so individual points have their distance reduced, keeping just the primordial information. The results were compared to identify the best classification cases. We have applied the proposed methodology to well-log data from a petroleum field of Campos Basin, Brazil. Sonic, gamma-ray, density, neutron porosity and deep induction logs were preprocessed with FastICA and DCT, and the product was classified with K-NN. The success rates in recognition were calculated by appling the method to log intervals where core data were available. The results were compared to those of automatic recognition of the original well-log data set with and without the removal of high frequency noise. We conclude that the application of the proposed methodology significantly improves the success rate of facies recognition by K-NN.

Estimation of dynamic petrophysical properties of water-bearing sands invaded with oil-base mud from the interpretation of multiple borehole geophysical measurements

Nonmiscible fluid displacement without salt exchange takes place when oil-base mud (OBM) invades connate water-saturated rocks. This is a favorable condition for the estimation of dynamic petrophysical properties, including saturation-dependent capillary pressure. We developed and successfully tested a new method to estimate porosity, fluid saturation, permeability, capillary pressure, and relative permeability of water-bearing sands invaded with OBM from multiple borehole geophysical measurements. The estimation method simulates the process of mud-filtrate invasion to calculate the corresponding radial distribution of water saturation. Porosity, permeability, capillary pressure, and relative permeability are iteratively adjusted in the simulation of invasion until density, photoelectric factor, neutron porosity, and apparent resistivity logs are accurately reproduced with numerical simulations that honor the postinvasion radial distribution of water saturation. Examples of application include oil- and gas-bearing reservoirs that exhibit a complete capillary fluid transition between water at the bottom and hydrocarbon at irreducible water saturation at the top. We show that the estimated dynamic petrophysical properties in the water-bearing portion of the reservoir are in agreement with vertical variations of water saturation above the free water-hydrocarbon contact, thereby validating our estimation method. Additionally, it is shown that the radial distribution of water saturation inferred from apparent resistivity and nuclear logs can be used for fluid-substitution analysis of acoustic compressional and shear logs.

Wavelet Analysis of Geophysical Well-log Data of Bombay Offshore Basin, India

Geophysical well-log (bore-hole) data facilitate understanding of the physical properties of the subsurface formations as a function of depth measured in a well. In the present study, the wavelet transformation technique was applied to the well-log data of three wells in the Bombay High oil field, India, in order to identify depths to the tops of oil and/or gas formation zones (pay zones). Continuous wavelet transformation (CWT) was performed on gamma-ray, resistivity, neutron porosity and velocity log data sets in order to determine the space-localization of the oil and/or gas formation zones. The choice of a mother wavelet is important and largely depends on the data under investigation. We have applied a variety of wavelets to the different log data sets to not only identify the depths to the tops of formation zones, but also to determine the optimum wavelet that best characterizes the pay zones. On examination of scalogram plots of each log corresponding to each wavelet for their better resolution in identifying the formation boundaries, we have found that the scalograms corresponding to the Gaus1 wavelet appeared to give the best resolution in identifying the depths of pay zones in all the well-log data sets of all three wells. To further validate the above observation, a histogram analysis of CWT coefficients is made. This showed that, of all the wavelets considered for the present study, Gaus1 wavelet is the most appropriate and optimum for determining the space-localization of pay zones in all the well-log data sets considered in the present study. The depths of pay zones estimated from scalogram plots of logs agree well with those provided by the Oil and Natural Gas Corporation Ltd., India.

Improved estimation of mineral and fluid volumetric concentrations from well logs in thinly bedded and invaded formations

Calculation of mineral and fluid volumetric concentrations from well logs is one of the most important outcomes of formation evaluation. Conventional estimation methods assume linear or quasi-linear relationships between volumetric concentrations of solid/fluid constituents and well logs. Experience shows, however, that the relationship between neutron porosity logs and mineral concentrations is generally nonlinear. More importantly, linear estimation methods do not explicitly account for shoulder-bed and/or invasion effects on well logs, nor do they account for differences in the volume of investigation of the measurements involved in the estimation. The latter deficiencies of linear estimation methods can cause appreciable errors in the calculation of porosity and hydrocarbon pore volume. We investigated three nonlinear inversion methods for assessment of volumetric concentrations of mineral and fluid constituents of rocks from multiple well logs. All three of these methods accounted for the general nonlinear relationship between well logs, mineral concentrations, and fluid saturations. The first method accounted for the combined effects of invasion and shoulder beds on well logs. The second method also accounted for shoulder-bed effects but was intended for cases where mud-filtrate invasion is negligible or radially deep. Finally, the third method was designed specifically for analysis of thick beds where mud-filtrate invasion is either negligible or radially deep. Numerical synthetic examples of application indicated that nonlinear inversion of multiple well logs is a reliable method to quantify complex mineral and fluid compositions in the presence of thin beds and invasion. Comparison of results against those obtained with conventional multimineral estimation methods confirmed the advantage of nonlinear inversion of multiple well logs in quantifying thinly bedded invaded formations with variable and complex lithology, such as those often encountered in carbonate formations.

Three‐dimensional stochastic estimation of porosity distribution: Benefits of using ground‐penetrating radar velocity tomograms in simulated‐annealing‐based or Bayesian sequential simulation approaches

Estimation of the three‐dimensional (3‐D) distribution of hydrologic properties and related uncertainty is a key for improved predictions of hydrologic processes in the subsurface. However it is difficult to gain high‐quality and high‐density hydrologic information from the subsurface. In this regard a promising strategy is to use high‐resolution geophysical data (that are relatively sensitive to variations of a hydrologic parameter of interest) to supplement direct hydrologic information from measurements in wells (e.g., logs, vertical profiles) and then generate stochastic simulations of the distribution of the hydrologic property conditioned on the hydrologic and geophysical data. In this study we develop and apply this strategy for a 3‐D field experiment in the heterogeneous aquifer at the Boise Hydrogeophysical Research Site and we evaluate how much benefit the geophysical data provide. We run high‐resolution 3‐D conditional simulations of porosity with both simulated‐annealing‐based and Bayesian sequential approaches using information from multiple intersecting crosshole gound‐penetrating radar (GPR) velocity tomograms and neutron porosity logs. The benefit of using GPR data is assessed by investigating their ability, when included in conditional simulation, to predict porosity log data withheld from the simulation. Results show that the use of crosshole GPR data can significantly improve the estimation of porosity spatial distribution and reduce associated uncertainty compared to using only well log measurements for the estimation. The amount of benefit depends primarily on the strength of the petrophysical relation between the GPR and porosity data, the variability of this relation throughout the investigated site, and lateral structural continuity at the site.

Origins of gypsum in deep carbonate reservoirs: Implications for hydrocarbon exploration and production

Gypsum can form penecontemporaneously in carbonate sediments, and it may be altered to anhydrite during burial. Some workers have suggested that gypsum dehydration is complete at burial depths of 3500 ft (1067 m); however, gypsum has been documented at depths as great as 13,100 ft (3993 m). Two examples of deeply buried gypsum illustrate contrasting origins. Gypsum in the Permian San Andres Formation in the Permian Basin of west Texas at a depth of 6000 ft (1829 m) occurs as anhydrite nodules with an outer rind of gypsum, suggesting that anhydrite was rehydrated to gypsum by interaction with interstitial brines. In contrast, gypsum in the carbonate beds of the Cretaceous Ferry Lake Anhydrite of the Mississippi Interior Salt Basin at 13,100 ft (3993 m) occurs as gypsum nodules with a rind of anhydrite, suggesting that the gypsum is primary and in the process of dehydration to anhydrite. These contrasting origins are likely a function of evaporite and carbonate stratigraphy. In the Permian Basin, a thick section of carbonate rocks is overlain by a relatively thin section of evaporites. In the Mississippi Interior Salt Basin, carbonates are interbedded with multiple evaporite beds, which inhibit circulation of interstitial brines. The burial temperature, pressure, and salinity of these formations suggest that gypsum could be preserved as primary or secondary gypsum. The presence of gypsum in reservoir rocks can affect porosity calculations, especially calculations using neutron porosity logs, which measure bound water of hydration in gypsum as porosity. Identification of gypsum at the depth of 13,100 ft (3993 m) indicates that log estimates of porosity in some deep carbonate reservoirs containing gypsum could have significant porosity and water saturation measurement errors.

Time-lapse sonic logs reveal patchy CO2saturation in-situ

[1] Based on time-lapse sonic and neutron porosity logs from the Nagaoka CO2 sequestration experiment, a P-wave velocity-saturation relation at reservoir depth is retrieved. It does not coincide with either of the end-member models of uniform and patchy saturation but falls in between even if realistic error estimates for the host rock properties are considered. Assuming a random distribution of CO2 patches it is shown that the mechanism of wave-induced flow can be evoked to explain this velocity-saturation relation. Characteristic CO2 patch size estimates range from 1 to 5 mm. Such mesoscopic heterogeneity can be responsible for attenuation and dispersion in the well logging frequency band.

Carbon dioxide storage potential for the Queenston Formation near the AES Cayuga coal-fired power plant in Tompkins County, New York

We evaluated the pore volume available for a specific potential geologic carbon dioxide (CO2) storage site in the Upper Ordovician Queenston Formation near the AES Corporation Cayuga coal-fired power plant in Tompkins County, New York. Core data collected 25 mi (40 km) from the plant reveal that the Queenston Formation is a relatively homogeneous fine- to medium-grained sandstone with hematite cement. Seismic and core data indicate that the formation was deposited in a fluvial system with mobile channels and has thickness maxima that trend north-northwest. Porosity is a major factor affecting geologic CO2 storage potential, and it is important to understand discrepancies among porosity measured from core plug, neutron porosity, density-derived porosity, and thin-section point count values. Relative to core plug–derived porosity values, the neutron porosity log is more reliable than the electron density porosity values. Thin sections reveal that hematite cement is the primary factor affecting porosity variability. Seismic, core, and well-log data suggest that in a 25-mi2 (65-km2) area surrounding this power plant, the Queenston Formation can sequester 18 million metric tons (11 million metric tons) of CO2 emission from the Cayuga power plant (8 yr of CO2 output, with a range of 3–12 yr), although many uncertainties must be better constrained to obtain a more accurate estimate. Because the Queenston Formation near the Cayuga power plant is relatively homogeneous, most of the formation at this location offers the potential for CO2 storage in its pore space.

Stochastic Bayesian inversion of borehole self-potential measurements

We propose a mechanistic model to compute and to invert self-potential log data in sedimentary basins and for near-surface geophysical applications. The framework of our analysis is founded in a unified electrical conductivity and self-potential petrophysical model. This model is based on an explicit dependence of these properties on porosity, water saturation, temperature, brine salinity, cementation and saturation (Archie) exponents and the volumetric charge density per unit pore volume associated with the clay fraction. This model is consistent with empirical laws widely used to interpret self-potential logs according to the two limiting cases corresponding to a clean sand and a pure shale. We present a finite element calculation of the self-potential signal produced by sand reservoirs interstratified with shale layers. For layered strata normal to the well, we demonstrate that the 3-D Poisson equation governing the occurrence of self-potentials in a borehole can be simplified to a 2-D axisymmetric partial differential equation solved at each depth providing a common self-potential reference can be defined between these different depths. This simplification is very accurate as long as the vertical salinity gradients are not too strong over distances corresponding to the borehole diameter. The inversion of borehole data (self-potential, resistivity and density well logs, incorporating information derived from neutron porosity and gamma-ray log data) is performed with the Adaptive Metropolis Algorithm (AMA). We start by formulating an approximate analytical solution for the six model parameters (water saturation, porosity, the two Archie's exponents, the pore water conductivity and the volumetric charge density of the diffuse layer). This solution is used for the AMA algorithm to converge in less than 60 iterations at each depth for the real case study. The posterior probability distributions are computed using 50–60 additional realizations. Our approach is applied to a case study concerning a small sedimentary sequence in the Piceance Basin, Colorado, in a series of tight gas reservoirs.

Linear iterative refinement method for the rapid simulation of borehole nuclear measurements: Part I — Vertical wells

As a result of its high numerical accuracy and versatility to include complex tool configurations and arbitrary spatial distributions of material properties, the Monte Carlo method is the foremost numerical technique used to simulate borehole nuclear measurements. Although recent advances in computer technology have considerably reduced the computer time required by Monte Carlo simulations of borehole nuclear measurements, the efficiency of the method is still not sufficient for estimation of layer-by-layer properties or combined quantitative interpretation with other borehole measurements. We develop and successfully test a new linear iterative refinement method to simulate nuclear borehole measurements accurately and rapidly. The approximation stems from Monte Carlo-derived geometric response factors, referred to as flux sensitivity functions (FSFs), for specific density and neutron-tool configurations. Our procedure first invokes the integral representation of Boltzmann’s transport equation to describe the detector response from the flux of particles emitted by the radioactive source. Subsequently, we use theMonte Carlo N-particle (MCNP) code to calculate the associated detector response function and the particle flux included in the integral form of Boltzmann’s equation. The linear iterative refinement method accounts for variations of the response functions attributable to local perturbations when numerically simulating neutron and density porosity logs. We quantify variations in the FSFs of neutron and density measurements from borehole environmental effects and spatial variations of formation properties. Simulations performed with the new approximations yield errors in the simulated value of density of less than [Formula: see text] with respect to Monte Carlo-simulated logs. Moreover, for the case of radial geometric factor of density, we observe a maximum shift of [Formula: see text] at 90% of the total sensitivity as a result of realistic variations of formation density. For radial variation of neutron properties (migration length), the maximum change in the radial length of investigation is [Formula: see text]. Neutron porosity values simulated with the new approximation differ by less than 10% from Monte Carlo simulations. The approximations enable the simulation of borehole nuclear measurements in seconds of CPU time compared to several hours with MCNP.

On replacing Am–Be neutron sources in compensated porosity logging tools

Authors explored the direct replacement of Am-Be neutron sources in neutron porosity logging tools through Monte Carlo simulations using MCNP5. (252)Cf and electronic accelerator neutron sources based on the Deuterium-Tritium fusion reaction were considered. Between the sources, a tradeoff was noted between sensitivity to the presence of hydrogen and uncertainty due to counting statistics. It was concluded that both replacement sources as well as accelerator sources based on the Deuterium-Deuterium fusion reaction warrant further consideration as porosity log sources.

MWD Vibration Measurements: A Time for Standardization

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 119877, "MWD Vibration Measure ments: A Time for Standardisation," by Svein Magne Osnes, SPE, StatoilHydro ASA; Per Amund Amundsen, SPE, University of Stavanger; and Tore Weltzin, SPE, Erik Nyrnes, SPE, Brita Lucie Hundstad, SPE, and Gaute Grindhaug, SPE, StatoilHydro ASA, originally prepared for the 2009 SPE/IADC Drilling Conference and Exhibition, Amsterdam, 17-19 March. The paper has not been peer reviewed. Since downhole vibration measurements were introduced in the early 1990s, these measurements have become extremely useful for improving drilling efficiency. Most operators will specify a vibration sensor of some sort to be run with most measurement-while-drilling (MWD) and logging-while-drilling (LWD) applications. Unlike most other downhole measurements, there is no industrial standard for how to sample, process, and present the vibration data. This raises a few issues that the full-length paper attempts to address. Introduction The lack of standardization of vibration measurements and vibration-data methodology recently has become apparent from several different points of view:Vibration readings cannot be correlated easily and compared from well to well, making it difficult to learn from experiences with different drill bits and drilling tools.It is difficult to use a fair and consistent policy to handle charges from service companies for tools that allegedly have been damaged or scrapped as a result of severe vibrations.Tool specifications from different service companies cannot be compared easily during tender evaluations.It is difficult to perform any form of quality control of contractor's vibration data, including calibration of vibration sensors.It is difficult for drilling engineers or drilling-contractor personnel to develop any universal skills in real-time drilling optimization on the basis of vibration data because the data are not comparable. Unlike vibration measurements, most other MWD and LWD data have been subjected to strict standardization. Similar standards exist for other formation measurements such as neutron porosity logging, density logging, and sonic logging, but no industry procedure or standards exist for the calibration, measurement range, or measurement principle of downhole vibration tools. Background During drilling, bottomhole equipment is subject to severe accelerations in the form of single or repetitive shocks and as sustained vibrations of the drillstring, both in the drilling direction and transverse to it. Such accelerations can interfere with the drilling operation and can cause equipment failures and destruction of downhole tools, which again has an undesirable effect on the operational costs as a result of time lost for tripping and charges for damaged equipment.

Estimating porosity with ground‐penetrating radar reflection tomography: A controlled 3‐D experiment at the Boise Hydrogeophysical Research Site

To evaluate the uncertainty of water‐saturated sediment velocity and porosity estimates derived from surface‐based, ground‐penetrating radar reflection tomography, we conducted a controlled field experiment at the Boise Hydrogeophysical Research Site (BHRS). The BHRS is an experimental well field located near Boise, Idaho. The experimental data set consisted of 3‐D multioffset radar acquired on an orthogonal 20 × 30 m surface grid that encompassed a set of 13 boreholes. Experimental control included (1) 1‐D vertical velocity functions determined from traveltime inversion of vertical radar profiles (VRP) and (2) neutron porosity logs. We estimated the porosity distribution in the saturated zone using both the Topp and Complex Refractive Index Method (CRIM) equations and found the CRIM estimates in better agreement with the neutron logs. We found that when averaged over the length of the borehole, surface‐derived velocity measurements were within 5% of the VRP velocities and that the porosity differed from the neutron log by less than 0.05. The uncertainty, however, is scale dependent. We found that the standard deviation of differences between ground‐penetrating‐radar‐derived and neutron‐log‐derived porosity values was as high as 0.06 at an averaging length of 0.25 m but decreased to less than 0.02 at length scale of 11 m. Additionally, we used the 3‐D porosity distribution to identify a relatively high‐porosity anomaly (i.e., local sedimentary body) within a lower‐porosity unit and verified the presence of the anomaly using the neutron porosity logs. Since the reflection tomography approach requires only surface data, it can provide rapid assessment of bulk hydrologic properties, identify meter‐scale anomalies of hydrologic significance, and may provide input for other higher‐resolution measurement methods.

Detection of productive intervals using acoustic wave velocity

Detection of productive intervals is a very important task in reservoir studies. Reliable reserve estimation and proper depth of production logging and well perforation depend upon accurate recognition of pay zones. In this study, velocity-permeability and velocity-deviation logs have been used to detect productive intervals for a carbonate oil reservoir. Permeability trends are revealed by constructing a velocity deviation log from a combination of the sonic log and the density and neutron porosity logs. Then the behaviour of acoustic waves in productive intervals is demonstrated and their application in the detection of productive intervals is described. This study shows that a productive interval has relatively low compressional and shear velocities, low impedance, small negative peaks of the velocity-deviation log and high porosity and resistivity. On the whole, this approach employing more criteria, prevents the possible errors of conventional methods which use simple cutoffs for defining pay zones.

Velocity-Porosity relationship in clastic formations – a case study from some parts of Niger Delta, Nigeria

Velocity-Porosity relationship in some parts of Niger Delta was studiesd with a view to establish the velocity-porosity relationship and the generalized equation(s) that best describe this relationship in clastic formations. Five wireline logs were acquired for the study. Neutron porosity log data was converted to synthetic velocity (VTA) using time-average equation of Wyllie (1956), and the sonic porosity log was converted to sonic velocity (Vsonic). The results were presented as velocity-porosity crossplots with the trend line equations and the coefficient of correlation. The results give a distinct inverse velocity-porosity relationship; i.e. velocity decreasing with increasing porosity. The velocity-porosity relationships established from both sonic log (Vsonic) and time-average formulation are best described by polynomial fitting of 2nd order. Two generalized equations of high coefficient of correlation, which can be used to calculate compressional velocity (Vp) from porosity values in clastic formations, were established from these relationship. Keywords: porosity, velocity, compressional, polynomial and clastic Global Journal of Pure and Applied Sciences Vol. 12(1) 2006: 125-128

Cálculo da porosidade em poços da Bacia de Almada - Ba com base num conjunto reduzido de perfis geofísicos de poço

In some oil boreholes, the geophysical well logs commonly applied to evaluate the geological formations included a set of logs such as sonic, gamma ray and resistivity, known as Project DT (PDT). Nowadays, the modern methods of reservoir study involve analysis of those logs plus density and neutron porosity logs, called Project RHOB/NPHI (PRN). By using both projects, it was possible to calculate and verify the variation of the effective porosity ( o e ) and the total porosity ( o t ), which are important parameters to characterize the fluid volume in a rock. In this context, it was used well log data from Namorado Field located in the Campos Basin/RJ, which has the complete set of logs (PRN), and thus, it can be used to validate the methodology performed by PDT. Later, this methodology was applied to the available data from Urucutuca Formation in Almada Basin/BA, where only PDT it is possible to perform. The values obtained for o e in the wells of Namorado Oil Field were around 0,20 to 0,30 for PDT, and, between 0,30 to 0,35 for PRN. In this case, it was observed that the applied methodology could be used to obtain o e from reservoirs with values 15% smaller in average. On the other hand, in Urucutuca Formation logs the estimated values for o t for 1-BAS-36-BA well varied between 0,30 to 0,50 in average, reaching a maximum value up to 0,65, and, o e changed between 0,30 and 0,35 in 57% of the data. For 1–SSA–01-BA well, o t varied between 0,30 and 0,65, reaching a maximum value of 0,80, and o e differed between 0,15 to 0,40 in 94% of the data. Therefore, it is possible to conclude that the approach used in the present study can be applied to estimate the petroleum reservoirs porosity to the exploration of sedimentary basins, in situations where it is available only a limited number of logs.