Laterolog Resistivity Research Articles

Novel Logging While Drilling Azimuthal Laterolog Resistivity Instrument Design for Oil-Based Mud

Novel Logging While Drilling Azimuthal Laterolog Resistivity Instrument Design for Oil-Based Mud

Logging-While-Drilling Laterolog vs. Electromagnetic Propagation Measurements: Which Is Telling the True Resistivity?

Summary The electromagnetic propagation (EMP) measurement frequently acquired with logging-while-drilling (LWD) tools in high-angle wells is sensitive to geometrical effects that can mask the true formation resistivity. Less commonly used, the LWD laterolog measurement is sometimes perceived as providing data too shallow to give a true formation resistivity (Rt). In this paper, we presents modeling and actual examples to demonstrate that the laterolog can often provide a superior resistivity measurement for formation evaluation to that of the LWD EMP tool. We examine the laterolog and EMP resistivities in several high-angle wells crossing carbonate formations in 8.5-in. and 6.125-in. hole sizes. In the 8.5-in. sections, producers and water injectors (high- and low-resistivity ranges) were evaluated. In the 6.125-in. sections, one reservoir sandwiched between two very high-resistivity layers and another borehole in a highly fractured reservoir were examined. The laterolog data were corrected for invasion using a 1D inversion of the memory data. Structure-based forward modeling was used to examine and explain the differences between the laterolog and EMP resistivity measurements. In the first example in a thick low-resistivity water reservoir, laterolog resistivity and EMP resistivity agree, showing that the two tools provide the same measurement when no geometrical effects are present. In the first part of the second example, a reservoir zone was initially drilled only with the LWD EMP resistivity measurement. The LWD laterolog was run several days later, and the resistivity data read much lower in the relogged section compared with the EMP resistivity. The laterolog 1D inversion was unable to resolve Rt because of the excessively deep invasion that occurred over the course of several days. In the second part of the second example, the laterolog resistivity showed a clear conductive invasion profile. While the deepest laterolog real-time resistivity data indicated lower resistivity than the EMP resistivity, the true resistivity, Rt (invasion-corrected 1D-inverted laterolog resistivity), matched the EMP Rt resistivity. This result validated both measurements and emphasized that the differences were due to invasion. The first two examples demonstrated that when acquired in normal drilling conditions (within 1–2 hours of drilling the section), the laterolog measurements can provide uninvaded formation resistivity even in the presence of invasion. A reservoir in another example was sandwiched between resistive layers that caused difficult-to-explain elevated EMP resistivity readings. Structural modeling reproduced the elevated behavior of the EMP data and explained the differences between resistivity measurements. This result showed that the laterolog is better suited to evaluate resistivity in thin reservoirs where there is a high-resistivity contrast to the adjacent layer. Finally, fractured reservoir examples are presented, which show that both the laterolog and EMP can be affected by the presence of fracture swarms. The examples presented in this paper demonstrate that in high-angle wells, when acquired under normal drilling conditions, invasion-corrected laterolog resistivity is often nearer to Rt than EMP resistivity. In those cases, the laterolog measurement provides data that are better inputs to water saturation calculations. Multiple examples from high-angle wells illustrate the findings.

Astronomically forced variations in multiresolution resistivity logs of lower Upper Cretaceous (Cenomanian-Coniacian) terrestrial formations from the Songliao Basin, northeastern China

Continuous and high-resolution well logs from the SK-2 east (SK-2e) borehole in the Songliao Basin provide an opportunity to understand the relationship between astronomically forced climate and electrical responses in terrestrial Cretaceous strata. Here, we present well logs, mud logs, and core measurement data of lacustrine deposits in the Upper Cretaceous Qingshankou Fm and of fluvial/deltaic deposits in the Quantou Fm. The multiresolution resistivity logs used for the cyclostratigraphic analysis include deep laterolog resistivity logs, resistivity image logs, and array induction logs. The results show that the resistivity of strata in Quantou Fm mainly reflects changes in clay content, and that resistivity logs can be used as paleoenvironmental and paleoclimate proxies in cyclostratigraphic studies of the Quantou Fm. For the Qingshankou Fm, formation resistivity is mainly affected by clay minerals, which contribute to the overall electrical conductivity, as well as nonconductive organic carbon. Increasing clay and organic carbon contents usually correspond to wetter and warmer climatic conditions. The phase relationship between resistivity logs and astronomical cyclicity depends on factors that control resistivity. Spectral analyses of lithological changes and resistivity logs indicate the presence of eccentricity, obliquity, and precession cycles throughout the Quantou Fm. This provides strong evidence that climate was the dominant control on cyclic sedimentation in the Quantou Fm. The floating astronomical timescale, which was established by calibrating extracted 405-kyr cycles from resistivity logs, reveals that the duration of Quantou Fm was approximately 5.5 Myr. Comparative analysis of power spectra reveals that the sensitivity of resistivity logs with specific resolutions to Milankovitch cycles with different frequencies is variable. Comprehensive analysis of multiresolution resistivity logs is a new method in cyclostratigraphy analysis that has the potential to be effective in detecting signals of Milankovitch cycles in terrestrial deposits.

Forward simulation of array laterolog resistivity in anisotropic formation and its application

A scaling-down experiment system of array laterolog resistivity was developed, and a corresponding formation model was built by 3D finite element numerical method to study the effect of different factors on the logging response quantitatively. The error between the experimental and numerical results was less than 5%, validating the reliability of the numerical simulation method. The single factor analysis of the formation relative dip, resistivity anisotropy and drilling fluid invasion was carried out by numerical simulation method, and the results show that: (1) The increase of relative dip can lead to the increase of formation resistivity, but the increasing value is relatively small, and the values of five array resistivity curves will reverse when the relative dip angle reaches a certain degree. (2) The increase of anisotropy coefficient λ can also cause the formation resistivity to rise, and the resistivity will increase by about 10% when λ increases from 1.0 to 1.5 in vertical wells. (3) Drilling fluid invasion has a more significant effect on the logging response than the former two factors. The order of the five curves will change due to drilling fluid invasion in anisotropic formation and the change rule is contrary to resistivity anisotropy. Taking the logging data of the Yingxi oilfield in the Qaidam Basin as an example, an anisotropic formation model considering drilling fluid invasion was built, and the numerical simulation results from the above methods were basically consistent with the logging data, which verified the accuracy of the method again. The results of this study lay a theoretical foundation for multiple-parameter inversion in anisotropic formation under complex well conditions.

Numerical and experimental simulations of multiarray azimuthal laterolog sonde responses in fractured reservoirs

The occurrence, orientation, and development of fractures are key parameters in the evaluation of carbonate and volcanic reservoirs. We have used a 3D finite-element method to numerically simulate the logging responses of a newly proposed multiarray azimuthal laterolog sonde (MALS) in a fractured formation. More importantly, a physical simulation performed with a scaled-down 3D resistivity apparatus was developed to verify the numerical simulation results. Comparative analysis indicated that the laterolog resistivity curves are controlled by the fracture dip angles. High-angle fractures normally correspond to positive differences in the array laterolog curves, whereas fractures with low dip angles consistently result in a negative difference. The MALS tool also provides an azimuthal resistivity measurement that can be used to determine the fracture dipping direction. The sine-wave trend in the 2D imaging of azimuthal resistivity displays the fracture occurrence. In addition, MALS can be used to identify vertical fractures around a borehole within a certain distance. In addition, combined with laterolog data, the fracture occurrence and extension length can be evaluated.

Series Expansion-Based Genetic Inversion of Wireline Logging Data

An evolutionary approach is applied to solve the nonlinear well logging inverse problem. In the framework of the proposed interval inversion method, nuclear, sonic, and laterolog resistivity data measured at an arbitrary depth interval are jointly inverted, where the depth variation of porosity, water saturation, and shale volume is expanded into series using Legendre polynomials as basis functions. In the interval inversion procedure, the series expansion coefficients are estimated by using an adaptive float-encoded genetic algorithm. Since the solution of the inverse problem using traditional linear optimization tools highly depends on the selection of the initial model, a heuristic search is necessary to reduce the initial model dependence of the interval inversion procedure. The genetic inversion strategy used in interval inversion seeks the global extreme of the objective function and provides an estimate of the vertical distribution of petrophysical parameters, even starting the inversion procedure from extremely high distances from the optimum. For a faster computational process, after a couple of thousand generations, the genetic algorithm is replaced by some linear optimization steps. The added advantage of using the Marquardt algorithm is the possibility to characterize the accuracy of the series expansion coefficients and derived petrophysical properties. A Hungarian oil field example demonstrates the feasibility and stability of the improved interval inversion method. As a significance, the genetic inversion method does not require prior knowledge or strong restrictions on the values of petrophysical properties and gives highly reliable estimation results practically independent of the initial model and core information.

Hydrocarbon saturation in upper Wolfcamp shale formation

Water saturation (Sw) and hydrocarbon saturation (Shc=1-Sw) estimates in hydrocarbon-bearing formations are generally derived from Dean-Stark core measurements, NMR log, and electromagnetic (EM) logs, such as induction log, galvanic resistivity (laterolog), or dielectric dispersion logs. In-situ estimation of hydrocarbon saturation in conventional reservoirs primarily rely on the deep-sensing or high-resolution EM logs. However, in the hydrocarbon-bearing shale formations, hydrocarbon saturation estimates obtained from EM logs tend to be unreliable. Conventional EM-log-interpretation models tend to break down for shale formations because they neglect the interfacial polarization effects and the dispersive behavior of EM properties of such geomaterials. This can be addressed by jointly processing the subsurface galvanic resistivity, induction, propagation and dielectric dispersion logs using an integrated model that accounts for the interfacial polarization mechanisms.One galvanic resistivity (laterolog) and dielectric dispersion logs, comprising 4 conductivity and 4 dielectric permittivity logs measured at four distinct frequencies, were acquired in a 520-feet depth interval of a well drilled in the upper Wolfcamp shale formation. We implement a novel log interpretation technique for the improved estimation of water saturation (Sw), brine conductivity (Cw), textural index/cementation exponent (m), and saturation exponent (n) in the upper Wolfcamp shale. Log processing was performed with an integrated mechanistic model, which combines Complex Refractive Index (CRI) model to analyze the conductivity and permittivity logs acquired at 1 GHz, Stroud-Milton-De (SMD) model to analyze the 3 conductivity dispersion and 3 permittivity dispersion logs in the frequency range of 10 MHz to 0.3 GHz, and Waxman-Smits (WS) model to analyze the deep galvanic resistivity log (RLA5) measured by the EM laterolog tool at 1 kHz.In the upper Wolfcamp shale, estimates derived from the joint inversion were robust in the presence of pyrite, low water saturation, and low porosity as compared to estimates from the inversion of only four-frequency dielectric dispersion logs. Formation brine conductivity and saturation-exponent estimates are more reliable compared to water saturation and cementation exponent estimates. Water saturation estimates obtained using the proposed methodology are compared against those obtained using multi-mineral inversion and those derived using CRIM model. Average relative errors in fitting the 1 laterolog resistivity and 8 dielectric dispersion logs using the estimates obtained from the proposed method are 10% and 20%, respectively, and their extreme values are 55% and 60%, respectively, in the 520-ft depth interval of the upper Wolfcamp shale formation.

Comprehensive evaluation of fracture parameters by dual laterolog data

Reservoir quality and productivity of tight formations depend heavily on the degree of fracture development. In fact, hard and dense carbonate formations may not be considered as net pay without the presence of fractures that convey fluids towards the wellbore. The evaluation of fractures is key to effective reservoir characterization for purposes like well drilling and completion as well as development and simulation of fractured reservoirs. Although imaging technologies such as Formation Micro-Scanners and Imagers (FMS and FMI) provide useful information about fracture properties (i.e., dip angle, porosity, aperture, and permeability), they are very expensive and may not be available in all wells. In this work, fracture parameters are estimated using conventional dual laterolog (DLL) resistivity which includes shallow (LLS) and deep (LLD) responses. This technique is based on electrical resistivity anomalies resulting from the separation of shallow and deep laterolog curves. Fracture parameters that can be calculated by DLL include dip angle, aperture, porosity, permeability, and cementation factor. The accuracy of the parameters calculated using DLL data is validated by the results of FMI in a well in one of the Iranian fractured reservoirs. Contrary to the image logs, the conventional DLL is run routinely in all drilled wells. Therefore, if a reservoir has limited and insufficient data of image logs, as it is often the case, the DLLs can be used as a reliable replacement in the construction of fracture models. Furthermore, DLL has an advantage of deeper evaluation of fractures in comparison with the immediate borehole investigation of image logs.

Advanced methods for the evaluation of a hybrid-type unconventional play: The Bakken petroleum system

Hybrid-type plays such as the Bakken petroleum system (BPS) can be particularly challenging from an interpretation, completion, or production perspective due to the mix of conventional and unconventional elements coexisting within a relatively short depth interval. In the BPS, conventional aspects include the presence of separate reservoir intervals, which, depending on your location within the basin, may include the Scallion, Middle Bakken, Sanish, and Three Forks. Unconventional aspects include the Lower Bakken and Upper Bakken shales, which are organic-rich shales comprising source rock and reservoir. Developing an accurate petrophysical evaluation of these formations requires a priori knowledge of the mineralogy, fluids, and geomechanical properties such that appropriate logging measurements, core analysis methods, and interpretation techniques can be obtained and used. During the development phase of an oil field, the log and core measurements being acquired and the petrophysical evaluation being performed may vary significantly from well to well across the field. Some wells may have triple-combo wireline or logging-while-drilling measurements consisting of bulk density, neutron porosity, and induction or laterolog resistivity, supplemented with a total gamma ray measurement. Borehole sonic logs may also have been acquired in some wells primarily for seismic calibration, geomechanical modeling, and hydraulic stimulation design. If the “standard” suite of measurements and petrophysical evaluation being provided fail to accurately represent the true complexity of the formations being evaluated, the asset valuation will, in most cases, be negatively impacted. Our formation evaluation of the BPS led to the identification of unique petrophysical challenges for each of the formations comprising the BPS. Traditional formation evaluation methods were applied to the BPS based on triple-combo measurements, a traditional petrophysical analysis, and the evaluation of net feet of pay. Advanced evaluation methods and techniques were then applied to address the petrophysical complexities identified with core evaluation, advanced log measurements, and discrepancies between the two. New petrophysical models were developed and fine-tuned to address the shortcomings of the simple models, and the net feet of pay were reevaluated using these new models. The detailed formation evaluation program used to characterize the BPS consisted of standard triple-combo logs supplemented with advanced downhole measurements including: (1) triaxial resistivity for thin-bed analysis, (2) nuclear magnetic resonance for porosity, free-fluid, and kerogen identification, (3) dielectric dispersion for water saturation, (4) geochemical spectroscopy for mineralogy and total organic carbon, and (5) dipole sonic for dynamic rock properties. Petrophysical models were developed using deterministic and probabilistic methods to integrate the measurements acquired for the most accurate analysis of porosity, saturation, and mineralogy and to best describe the hydrocarbon production potential of the BPS.

A completion staging case study in the Barnett Shale using advanced LWD quadrapole sonic and borehole imaging

Horizontal completions within a complex oil condensate window of the Barnett Shale have proven challenging because of problematic well placement within an optimum reservoir section and the vertical and mechanical proximity to mobile water in the Viola Limestone. Accurate formation properties along the horizontal well are required to identify both conditions in order to effectively avoid water production.At the request of the operator, a post-mortem study was conducted on a horizontal well in the Lower Barnett Shale to determine the cause of excessive water production. Completion optimization studies are typically conducted using wireline tools; however, for the purposes of this study, an advanced LWD logging suite consisting of electromagnetic azimuthal resistivity, neutron, azimuthal density, laterolog resistivity imager, and quadrapole sonic was run on the well. An integrated interpretation of all sensor data was used to first confirm the stratigraphic placement of the well and then evaluate effective porosity, anisotropic closure stress, geologic texture, and natural fracture distribution.Fracture stages and cluster stages were then selected to target similar rock and lowest closure stress along the well, while taking into consideration the existing natural fractures determined from the image log. Fracture-stage placement data, chemically traced production flow, and a flowing temperature log were all used to interpret well flow vs. the actual perforation cluster positions.This paper presents conclusions drawn regarding both the engineering evaluation criteria used to fracture the well, as well as the geologic-based texture and fracture interpretation that explains the ultimate well performance. Finally, a new automatic staging and cluster-placement software solution was employed to use insight gained from the case study well to better plan future horizontal completions within the field.

New Methods for Modeling Laterolog Resistivity Corrections

The paper presents methods for laterolog response modeling. In Coulomb’s charges method, Laplace’s equation is solved for the electric field distribution in rock medium with internal boundaries between different resistivity layers. There, the boundary problem is reduced to Fred-holm integral equation of the second kind. The second method uses a finite element array to model apparent resistivity from laterolog. The task is treated as DC problem and the Laplace equation is solved numerically. The presented methods were applied to borehole data covering a typical stratigraphie section of the Fore-Sudetic Monocline in southwestern Poland. Apparent resistivity was calculated using the Coulomb’s charges method and alternatively modeled using a finite element method which gave similar results. Then, a series of linear corrections for borehole, shoulder bed, and filtration effects for apparent resistivity obtained by the Coulomb’s charges method demonstrated the feasibility of calculating true resistivity of virgin and invaded zones. The proposed methods provide a flexible solution in modeling which can be adapted to other logs.

Electrofacies analysis for coal lithotype profiling based on high-resolution wireline log data

The traditional approach to coal lithotype analysis is based on a visual characterisation of coal in core, mine or outcrop exposures. As not all wells are fully cored, the petroleum and coal mining industries increasingly use geophysical wireline logs for lithology interpretation.This study demonstrates a method for interpreting coal lithotypes from geophysical wireline logs, and in particular discriminating between bright or banded, and dull coal at similar densities to a decimetre level. The study explores the optimum combination of geophysical log suites for training the coal electrofacies interpretation, using neural network conception, and then propagating the results to wells with fewer wireline data. This approach is objective and has a recordable reproducibility and rule set.In addition to conventional gamma ray and density logs, laterolog resistivity, microresistivity and PEF data were used in the study. Array resistivity data from a compact micro imager (CMI tool) were processed into a single microresistivity curve and integrated with the conventional resistivity data in the cluster analysis. Microresistivity data were tested in the analysis to test the hypothesis that the improved vertical resolution of microresistivity curve can enhance the accuracy of the clustering analysis. The addition of PEF log allowed discrimination between low density bright to banded coal electrofacies and low density inertinite-rich dull electrofacies.The results of clustering analysis were validated statistically and the results of the electrofacies results were compared to manually derived coal lithotype logs.

Electrofacies analysis using high-resolution wireline geophysical data as a proxy for inertinite-rich coal distribution in Late Permian Coal Seams, Bowen Basin

This paper examines the stratigraphic and geographic distribution of coal composition in main Late Permian coal measures in the Bowen Basin, using coal electrofacies as a proxy for inertinite maceral group content. Data for this research were derived from some 26 wells in the northern part of the Bowen Basin. A companion paper (Roslin and Esterle, 2015, in review) introduced the methodology, which is based on electrofacies analysis and uses high-resolution wireline data (including microresistivity from Compact Micro-Image (CMI) tool and Photoelectric Factor (PEF) data in addition to conventional gamma ray, density and laterolog resistivity) to obtain coal electrofacies. Validation of the methodology was performed by comparison of the weighted average proportion of coal electrofacies to the weighted average proportion of the corresponding coal lithotypes obtained from millimetre scale logging and to the percentage gathered from maceral content analysis. The weighted average proportion of the interpreted dull inertinite-rich coal electrofacies (independent of rank and heat effects) was then analysed to determine their stratigraphic and geographic distribution.From the base upward, the main Late Permian coal bearing units are the Moranbah Coal Measure (MCM), Fort Cooper Coal Measure (FCCM), and Rangal Coal Measure (RCM) and their stratigraphic equivalents across the basin. The proportion of inertinite-rich dull coal electrofacies increases upwards in the RCM, with some thick and merged seams showing distinctive electrofacies signatures. Within the study area, the coal measures and individual seams split from north to south, reflecting increased subsidence and sediment influx into basin depocentres. As the seams split, the proportion of inertinite-rich dull coal electrofacies decreases in the tested sample set.

Numerical simulation of high-resolution azimuthal resistivity laterolog response in fractured reservoirs

The high-resolution azimuthal resistivity laterolog response in a fractured formation was numerically simulated using a three-dimensional finite element method. Simulation results show that the azimuthal resistivity is determined by fracture dipping as well as dipping direction, while the amplitude differences between deep and shallow laterolog resistivities are mainly controlled by the former. A linear relationship exists between the corrected apparent conductivities and fracture aperture. With the same fracture aperture, the deep and shallow laterolog resistivities present small values with negative separations for low-angle fractures, while azimuthal resistivities have large variations with positive separations for high-angle fractures that intersect the borehole. For dipping fractures, the variation of the azimuthal resistivity becomes larger when the fracture aperture increases. In addition, for high-angle fractures far from the borehole, a negative separation between the deep and shallow resistivities exists when fracture aperture is large as well as high resistivity contrast exists between bedrock and fracture fluid. The decreasing amplitude of dual laterolog resistivity can indicate the aperture of low-angle fractures, and the variation of the deep azimuthal resistivity can give information of the aperture of high-angle fractures and their position relative to the borehole.

Sensitivity analysis in permeability estimation using logging and injection-falloff test data for an anthracite coalbed methane reservoir in Southeast Qinshui Basin, China

This paper presents a sensitivity analysis in permeability estimation by interpreting injection-falloff test and logging data for a producing coalbed methane field in Southeast Qinshui Basin. Injection-falloff test data are interpreted by an infinitely acting, constant compressibility and radial homogeneous model. Log interpretation is based on the Archie equation using data of shallow laterolog resistivity. The cementation factor of coal is calculated using laboratory measurements. Based on the interpreted cementation factors and the assumed fracture geometries, the sensitivity in permeability estimation using logging data is analyzed. Results show that the permeabilities are 0.041, 0.012 and 0.035mD for coal seam #3 in wells #W-1, W-5 and W-6, respectively, from the interpretation of injection-falloff test data; the calculated coal cementation factors range widely from 0.9 to 1.8 with average of 1.3. In order to match the log interpretation results with those from injection-falloff tests, different fracture spacing is used in log interpretation for the three wells. The fracture spacing varies from 0.39 to 0.67mm, and the average fracture aperture varies from 0.229 to 0.398μm for the three wells. The cementation factor has the highest impact on estimation of permeability if the cementation factor, mud filtrate resistivity and fracture spacing are varied with 10% from the base case. Effect of fracture aperture’s heterogeneity on permeability is depending on the standard deviation and average of fracture aperture. Effective permeability has a stronger relationship with geometric mean of face and butt cleats aperture than with total porosity for different face and butt spacing models.

Geomechanics and fluid flow effects on electric well logs: multiphysics modeling

Coupled geomechanic and fluid flow analysis is applied to develop theoretical and experimental background for geosteering and well logging to diagnose the state of near-wellbore formation and oil reservoir. The suggested methods of processing EM induction (VIKIZ) and Russian laterolog (RLL) resistivity responses account for effects of stress-dependent fluid flow changes. The geomechanic and fluid-flow effects on resistivity well logs are investigated for the case of asymmetric invasion and related irreversible deformation. Ways of taking into account stress-dependent effects on resistivity logs are developed on the basis of 3D modeling of geomechanic and electromagnetic fields.

Identification of natural gas fractured volcanic formation by using numerical inversion method

Abstract The difference between formation resistivity and tight surrounding rock resistivity is caused by reservoir fractures and fluid property in the pore space, when factors such as mudstone, pore and other conductive minerals are eliminated. Therefore, the use of volcanic lithology identification, the resistivity of gas-bearing reservoir, and tight surrounding layer with the same lithology are selected to determine the formation true resistivity formula for gas-bearing intervals, which eliminates the factors of reservoir factures and fluid property in the pore space through numerical inversion methods. Thus, the difference-ratio value of structural resistivity is defined as the ratio of difference between formation true resistivity and deep investigation laterolog resistivity to deep investigation laterolog resistivity. Such parameters reflect the influence of reservoir fractures and fluid property in the pore space for the reduced rate of resistivity, so it identifies fluid property of volcanic fractured formation. Finally, the identification plate of oil layer, gas layer, and water layer for volcanic reservoir is established. Therefore, the natural gas layers of volcanic fractured formation are effectively evaluated and identified in combination with other well logging curves, reservoir performance data, and gas surveying information.

A correction method of deep laterolog responses under under-balanced logging conditions

Abstract Under-balanced drilling and under-balanced logging are very important techniques for directly identifying and protecting hydrocarbon reservoirs and enhancing productivity. The wellhead assembly under under-balanced logging is greatly different from that under conventional logging. Therefore, the length of cable electrode for dual laterolog should be reduced to adapt to the wellhead assembly, which causes the deep laterolog responses to drop and cannot truly reflect the reservoir property. The rule of electrode coefficient varying with the cable electrode length under under-balanced conditions has been computed using finite element method, that is, the longer the cable electrode, the smaller the electrode coefficient. The deep laterolog resistivity correction method under under-balanced condition is introduced. Field data examples are used to test the new method and shows that this method is reliable. This method can be used to any length of cable electrode and can be applied to field pretreatment directly. The corrected deep laterolog resistivity can be used in logging interpretation and quantitative hydrocarbon evaluation.

High-resolution characterization and integrated study of a reservoir formation: the danian carbonate platform in the Aquitaine Basin (France)

This paper provides an example of an integrated multi-scale study of a carbonate reservoir. The Danian Lower R2 carbonate reservoir is located in the South of the Aquitaine Basin (France) and represents a potential underground gas storage site for Gaz de France. The Danian Lower R2 reservoir was deposited as a prograding carbonate platform bordered by a reef barrier. The effects of sedimentary and diagenetic events on the reservoir properties, particularly dolomitization, were evaluated. In this study, the reservoir quality has been assessed by seismic analyses at the basin scale, by log-analysis at the reservoir scale, by petrographic methods and by petrophysical tools at the pore-core scale. Two dolomitization stages, separated by a compaction event with associated fracturing and stylolites, have been identified. These diagenetic events have significantly improved the Lower R2 carbonate reservoir properties. It is demonstrated that the reservoir quality is mainly controlled by the pore-geometry, which is determined by various diagenetic processes. The permeability values of the reservoir range over 4 orders of magnitude, from 0.1 to 5600 mD and the porosity values range between 2 and 42%. Reservoir unit 4 (a karstic dolomite) shows the best reservoir properties with average porosity values ranging between 11.1% and 19.3% and an average permeability ranging between 379 and 766 mD. Reservoir unit 2 (a fine-grained limestone) shows the worst reservoir properties. The cementation factors range from 1.68 to 2.48. The dolomitic crystal carbonate texture (mainly units 3 and 4) shows the highest value of the cementation factor (1.98–2.48) and formation factor (9.54–36.97), which is due to its high degree of cementation. The saturation exponents vary between 1.2 and 3.4. Using these experimental electrical parameters and the resistivity laterolog tool we predicted the water saturation in the various reservoir units. The permeability was predicted by combining the formation factor with the micro-geometric characteristic length. The best fit is obtained with the Katz and Thompson's model and for a constant of 1/171.