Shaly Sand Research Articles

LITHOLOGY INTERPRETATION BASED ON WELL LOG DATA ANALYSIS IN “JS” FIELD

Reservoir lithology types in a prospect zone of hydrocarbon can be known through well log data analysis, both qualitatively and quantitatively. Lithology interpretation based on qualitatively well log data analysis, has been successfully carried out by K-1 and K-3 well log data on JS Field, West Natuna basin, Riau Islands.Main focus of the research is types of lithology indicated by response the petrophysical well data log of Lower-Middle Miocene Arang Formation. Arang Formation was deposited immediately on top Barat formation and depositional environment in this formation is transitional marine - marine. Petrophysics log shows well data are log gamma ray, resistivity, neutron porosity, density, and sonic. The limitation of study are on four types lithology, they are coal, sand, sally sand, and shale. Lithology on well K-1 dominate by shale, there is thin intersection between sand and coal. The well of K-1 have sand thickest around six meter. While on well K-3 Petrophysics log data shows thin intersection between coal, sand, shaly sand, and dominated by shale. The thickest Sand have thickness 29 meter, and thicker than on K-1 well. The result in this study, the formation dominated by types of lithology “shale”.

A novel method to improve water saturation in shaly sand reservoirs using wireline logs

Water saturation in shaly reservoirs is a difficult task due to the heterogeneity nature of shale and the way the shale distributed in the reservoirs. So, many scientists proposed several models for water saturation in shaly sandstone reservoirs. So far, the most reliable techniques depend on identification of shale habitat qualitatively to apply suitable water saturation model, these techniques can lead to inaccurate identification of shale habitat, especially when dealing with a mixture of different shale modes and massive superimpose well logging data, and hence drastically erroneous values of water saturation and hydrocarbon reserves. Well logs and routine core analysis from two main fields in Egypt. The North Sinai and the Gulf of Suez fields are used for this study to evaluate the novel proposed method. Unlike other qualitative methods, a new robust method has been introduced to determine accurate volumes of shale distribution types. This volumetric method checked for validation and accuracy using Thomas-Stieber crossplot, the results show good and a reliable degree of accuracy. Consequently, appropriate water saturation models can apply accurately. While the dispersed shale model is adequate to estimate water saturation in dispersed shale reservoirs, water saturations for laminated shaly sand reservoirs are more complicated. So, a new approach and algorithms have been introduced to evaluate water saturation in these complex problematic reservoirs specifically in the absence of triaxial induction resistivity measurements. Furthermore, to prove the superiority of this novel method over traditional techniques, a comparative study and statistical analysis performed between the new water saturation method and conventional techniques by using InetillLog software © 2015. These comparisons and statistics show a remarkable discrepancy and variance in values between conventional methods and the new method, where water saturation values obtained from conventional methods for two fields are drastically lower than the new method. This can lead to erroneous water saturation and hydrocarbon estimations. Water saturations derived from the new method were in perfect agreement with the corresponding water saturations from cores data. Moreover, scatter diagrams between water saturation from novel method and that from core analysis obtained correlation coefficient (R2) values of 0.82, 0.85, for the North Sinai and the Gulf of Suez fields, respectively, indicating strong linear relationships. Furthermore, this new method is taken care of one of several pitfalls of LSSA interpretation method. So, this novel method adds a valuable improvement in water saturation, the assessment of hydrocarbon saturation in shaly reservoirs, continuous Net To Gross (NTG) calculations, net pay detection, reservoir simulation, and reserve estimation.

Modeling of porosity and permeability for hydrocarbon Exploration: A case study of Gongola arm of the Upper Benue Trough

Irreducible water saturation is one of the fundamental parameters in characterizing hydrocarbon formations, playing key role in volumetric and recovery calculations and permeability definition within a reservoir. The determination of the reservoir permeability using the irreducible water saturation in a shaly sand transition zone has been problematic due to the presence of the bound water saturation. In this research, a model was developed based on the Coates and Dagan permeability model formulation using the dual water model parameters. In this model formulation using the three models, a sensitivity coefficient for conditioning the permeability field at the transition zone was introduced. The sensitivity factor is a quotient function of bound water saturation and the total water saturation. The localized nature of the well data in the determination of the depositional architecture (porosity and permeability) were extrapolated away from or interpolated between acquisition locations using the areal coverage provided by seismic data. The analysis of the well information from the Kolmani River showed that the hydrocarbon lies at depth between 2071m and 2194m (Cenomenian-Turonian Yolde formation). The acoustic map within the reservoir shows the occurrence of dense uniform marine shales and sandstones. It also shows the depositional process has been uniform and sequential. High density clastic materials were also discovered within the reservoir. The permeability results obtained by equating the bound water and total water saturations to the irreducible water saturation gave the 26mD and 16mD as the upper (clean sand) and lower (pure shale) limits of the effective permeability values for the reservoir. The result obtained using the new model showed that the effective permeability is 21mD within the transition zone. Other petrophysical results showed that the reservoir has an effective porosity of 20% and effective water saturation of 12%. Based on these reservoir results, it is understood that the well is highly compact and will not flow during production.

Electrical formation factor of clean sand from laboratory measurements and digital rock physics

Abstract. Electrical properties of rocks are important parameters for well-log and reservoir interpretation. Laboratory measurements of such properties are time-consuming, difficult, and impossible in some cases. Being able to compute them from 3-D images of small samples will allow for the generation of a massive amount of data in a short time, opening new avenues in applied and fundamental science. To become a reliable method, the accuracy of this technology needs to be tested. In this study, we developed a comprehensive and robust workflow with clean sand from two beaches. Electrical conductivities at 1 kHz were first carefully measured in the laboratory. A range of porosities spanning from a minimum of 0.26–0.33 to a maximum of 0.39–0.44, depending on the samples, was obtained. Such a range was achieved by compacting the samples in a way that reproduces the natural packing of sand. Characteristic electrical formation factor versus porosity relationships were then obtained for each sand type. 3-D microcomputed tomography images of each sand sample from the experimental sand pack were acquired at different resolutions. Image processing was done using a global thresholding method and up to 96 subsamples of sizes from 2003 to 7003 voxels. After segmentation, the images were used to compute the effective electrical conductivity of the sub-cubes using finite-element electrostatic modelling. For the samples, a good agreement between laboratory measurements and computation from digital cores was found if a sub-cube size representative elemental volume (REV) was reached that is between 1300 and 1820 µm3, which, with an average grain size of 160 µm, is between 8 and 11 grains. Computed digital rock images of the clean sands have opened a way forward for obtaining the formation factor within the shortest possible time; laboratory calculations take 5 to 35 d as in the case of clean and shaly sands, respectively, whereas digital rock physics computation takes just 3 to 5 h.

Prediction of high-resolution reservoir facies and permeability, an integrated approach in the Irwin River Coal Measures Formation, Perth Basin, Western Australia

Traditionally, prediction of facies and permeability for a reservoir rock was one of many challenges in the industry that necessitates advanced and sophisticated evaluation for effective reservoir description. Three wells have been studied in the Perth Basin in Western Australia across the shaly sand of the Irwin River Coal Measures Formation, which contain a comprehensive suite of advanced and conventional logs. Due to the reservoir heterogeneity and the clay distribution, it is very challenging to resolve the effective pore volume, the reservoir facies and how the high permeability zones are distributed within the formation.In this paper, a new technique has been successfully tested on the Shaly Sand by integrating the nuclear magnetic resonance (NMR) and the conventional density log. The method allows the establishment of high-resolution facies classification for the reservoir using an Equivalent Flow Zone Indicator Index (EFZI). The studied core facies have been integrated with the EFZI into a new workflow to distribute facies on a larger scale in the uncored wells.Four hydraulic flow units (HFU) have been defined from one cored well using Flow Zone Indicator approach, with each has a unique FZI value and different permeability model based on core measurements. The EFZI-based high-resolution facies have been validated at several formation depths using the core thin sections to ensure the best calibration will be obtained for facies log, hence the permeability log-to-core match.The methodology will help running an advanced petrophysical analysis for the zone of interest and will reduce the parameters uncertainty. Application of this methodology in the uncored wells has shown very encouraging results, which is believed it can be used in the absence of any core data to resolve the rock typing from the well logs.

Delineation of aquifer potential zones using hydraulic parameters in Gombe and environs, North-Eastern, Nigeria

This research is aimed at delineating the groundwater potential zones in Gombe and environs using Dar Zarrouk parameters. The study area is located within longitudes 11°7′0″E to 11°14′0″E, and latitudes 10°15′0″N to 10°21′0″N, it is basically underlain by basement Complex rocks represented by Diorite and Granites, and Cretaceous sedimentary rocks represented by Bima, Yolde, Fika and Gombe Formations. Thirty two (32) vertical electric soundings (VES) using Schlumberger array method with the aid of ABEM Signal Averaging System (SAS) Terrameter was used for the data acquisition. The result of the interpretation shows four to six geo-electric layers. The geo-electric section revealed the major aquifers to be confined and semi confined and consist of Medium grain sandstones, with varying thicknesses. The aquifer hydraulic characteristics indicated that the transverse resistance, ranges from 235.2Ωm2 to 6317.87Ωm2 with an average value of 1789.50Ωm2. The Longitudinal conductance, S, ranges from 0.1415Ωm to 31.933Ωm with an average of 2.002Ωm. The Hydraulic conductivity value range from 2.62m/day to 138.66 m/day with a mean value of 20.662 m/day. The transmissivity values obtained for the various layers range from 78.34 m2/day to 13284.02m2/day, with the average value been 893.57 m2/day. Four groundwater potential zones were delineated including medium grain sandstones, Sandstones, clayey sand and shaly sand.

Evaluation of laminated shaly sand sequences in Ahwaz oil field using (via) high-resolution square logs

Thinly bedded and laminated shale-sand sequences are very common in most of the producing formations in Iran. Historically, traditionally well logging methods such as conventional resistivity measurement is employed to evaluate pay intervals in order to extract information about hydrocarbon saturation. However, there is the practical matter of resolution of these methods to detect thin laminated shaly sand layers. In order to cope with this limitation, other technique such as: high-resolution method should be utilized. For doing this method, we receive low-resolution logs and a high-resolution log from a well logging tool that is disposed in a wellbore which has laminated shaly sand layers. Firstly, square log is produced then these logs are convolved with vertical response function of well logging tools to generate constructed log. The constructed logs are compared with low-resolution logs, if these two logs are matched we choose that square logs as optimum square logs and analyze them. But if these two logs do not match, the square logs undergo interactive refinement then these refined logs are subsequently convolved with a vertical response function of the well logging tool thereby producing a constructed log. Then these constructed logs compare with low-resolution logs. This work repeated until these logs are matched and the optimum square logs are chosen. High-resolution square log method is an iterative method, time consuming and also has very mathematical calculations because we developed a computer program with MATLAB software which can do all these works with high accuracy and low time.

A nonparametric approach using clustering analysis to estimate shaliness in shaly-sand formations

This work proposes an approach to estimate the clay content of shaly sand formations using Machine Learning techniques. Currently, the main methodology used to investigate shaliness is based on a set of parameters defined by interpreters. In this manuscript, we present an nonparametric approach to analyze well logs aiming at automatically estimating such parameters by performing two straightforward steps: i) firstly, a clustering algorithm is used to extract patterns to confirm the gamma-ray log bimodal distribution behavior; ii) secondly, we use Gaussian mixture models to calculate the shales and sandstones means and standard deviations to set the necessary parameters to obtain the shaliness. Another strategy, adopting a similar methodology, was perfomed using the resistivity log to compute the shaliness. Experiments emphasize the importance of our approach, presenting outstanding results and allowing us to identify important petrophysical properties, like the shaliness in shaly sand models, in accordance with interpreters opinion.

Porosity and carbon dioxide storage capacity of the Maryville–Basal sands section (middle Cambrian), Southern Appalachian Basin, Kentucky

The middle Cambrian Maryville–Basal sands in the interval of 4600–4720 ft (1402.1–1438.7 m) in the Kentucky Geological Survey 1 Hanson Aggregates well (i.e., muddy sandstones separated by sandy mudstones) were evaluated to determine effective porosity (φe), clay volume (Vc), and supercritical CO2 storage capacity. Average porosity and permeability measured in core plugs were 8.71% porosity and 2.17 md permeability in the Maryville sand and 10.61% porosity and 15.79 md permeability in the Basal sand. The φe and Vc were calculated from the density log using a multiple-matrix shaly sand model to identify four formation lithologies: muddy sandstone, sandy mudstone, dolomitic mudstone, and dolomitic claystone. Average φe and Vc calculated in the Maryville sand were 8.9% and 35.3%, respectively, and an average of 8.7% and 41.2% in the Basal sand, respectively. Calculated φe exhibits a good match with porosity measured in core plugs. Prior to step-rate testing, static reservoir pressure was 2020 psi (13.9 MPa), representing a 0.435 psi/ft (9.8 kPa/m) hydrostatic gradient, which is consistent with other underpressured reservoirs in Kentucky. The interval fractured at 2698 psi (18.0 MPa), yielding a fracture gradient of 0.581 psi/ft (12.7 kPa/m). Pressure falloff analysis suggests a dual-porosity/dual-permeability reservoir consistent with core data. Estimated 50th percentile supercritical CO2 storage volume supercritical CO2 storage volume, using 7% porosity cutoff for determining net reservoir volume, is 0.538 tons/ac (1.33 t/ha). Thin reservoir sands, low porosity and permeability, and low fracture gradient, however, preclude the Maryville–Basal sands as large-volume deep-saline CO2 storage reservoirs in this area.

Petrophysical analysis of well logs for reservoir evaluation: a case study of “Kadanwari” gas field, middle Indus basin, Pakistan

Our study focuses on the interpretation of wire-line logs to evaluate the hydrocarbons potential of sandstone reservoir in the Kadanwari gas field, Sindh, Pakistan. We have considered wire-line logs of four drilled wells (K-01, K-03, K-10, and K-11) in the research area and interpreted 13 reservoir zones. Analytical reservoir analysis includes the shale content (Vsh), effective porosity (Oeff), hydrocarbon and water saturation (Shc and Sw), and net pay thickness variations. Hydrocarbon-bearing zone characterized by high resistivity values, porosity high, permeability high, saturation of water low, and less Vsh suggest clean sand. The petrophysical analysis revealed the hydrocarbon potential of lower Goru sandstone packages at different levels (2886–3797 m). The petrophysical parameters of sub-reservoirs were carefully analyzed which are ranked as good quality sand reservoirs with average effective porosities ranging from 0.11–0.44%, average water saturation ranging from 0.18–0.45%, hydrocarbon saturation averaging between 0.59–0.86%, and permeability ranging from 10.539 to 477.76 m Darcy. Water saturation for heterogeneous shaly sand reservoirs was successfully tested by Indonesian model which suggests that Sw in each well is fewer than 60% therefore over all the region bearing good quality of hydrocarbon potential of the targeted formation and selected zones. The vertical and horizontal variations of reservoir parameters are studied through constructing the litho-saturation cross-plots and isoparametric maps of the petrophysical parameters, respectively. The isoparametric maps help to visualize the geographical distribution of reservoir configuration in the subsurface. The petrophysical estimates of this study appraise the national conventional fuel treasure of lower Goru formation in Kadanwari gas fields and suggest new prospects to drill more wells on the central portion of the southwestern part of the study area. The neighboring area to the south of Kadanwari-01 is economically viable for hydrocarbon exploration. The northeastern side of the study area is avoided due to the high concentration of water and excessive shale content.

A new experimental multi-physics method for quantifying cation exchange capacity of shaly-sand formations

In this paper, a new method is proposed to quantify cation exchange capacity (CEC) in rocks with complex mineralogy and in the presence of multiple types of clay minerals by integrating nitrogen adsorption-desorption, nuclear magnetic resonance (NMR), and X-ray diffraction (XRD) measurements (including quantitative XRD). In the new method, a successive controlled nitrogen adsorption-desorption measurements as well as NMR measurements were performed on multiple samples from the same rock type. Then, an inversion algorithm was introduced to estimate surface area and volume of hydration water of each mineral, which were used as inputs to our recently-developed novel physics-based CEC estimation workflow. The CEC estimates obtained from the new method were compared against those from the ammonium acetate method and inductively coupled plasma mass spectrometry (ICP-MS) measurements in synthetic and actual powdered shaly sand rock samples. The results showed that the CEC estimates from the two methods were in good agreement, with less than 4 meq/100 g difference (i.e., average relative error of less than 23%). The experimental results demonstrated reliability of the proposed method for CEC quantification in clay-rich formations with complex lithology in the presence of multiple types of clay minerals.

Evaluation of gas hydrate saturation by effective medium theory in shaly sands: a case study from the Qilian Mountain permafrost, China

Gas hydrate saturation calculation is a complex problem in the evaluation of gas hydrate reservoirs in the Qilian Mountain permafrost. From observations of the actual rock samples and experimental results from scanning electron microscopy images, gas hydrate reservoirs contain some extent of laminated and dispersed clay that affects the resistivity response of formation rocks. In light of this situation, we need to consider the influence of clay content when we evaluate the saturation of gas hydrate reservoirs in the studied area. We establish two kinds of resistivity models according to the distribution of clay and obtain corresponding methods to evaluate the saturation of gas hydrates based on the effective medium theory (EMT). The results show that the clay content in the shaly sand reservoirs varies over a large range, from 3.0 to 45.0%, and the average value is 19.4% indicating a high clay content overall. The comparison between experimental resistivity and simulated results show that the models based on EMT can be used to characterize the resistivity of reservoirs with different clay distributions. In the DK-2 well, the mean value of gas hydrate saturation obtained by the EMT is 35.6%, whereas that estimated using the Archie equation is 9.5%. In the DK-3 well, similarly, the mean value of gas hydrate saturation obtained by the EMT is 34.4%, whereas that estimated using the Archie equation is 15.5%. The gas hydrate saturation obtained from the EMT is higher than that obtained from the Archie equation because the former takes into account not only the content but also the distribution of clay. The method based on EMT is more effective for identifying and estimating gas hydrate reservoirs in the Qilian Mountain permafrost.

English

Shales in the reservoir causes complications for the petrophysicist because they generally are conductive and mask the high resistance characteristic of hydrocarbons. Data from a suite of well logs were used to estimate the effect of reservoir shaliness on petrophysical parameters of some reservoir rocks of the eastern Niger Delta Basin. The log section was digitized using Neuralog software. Delineation of the productive clean and dirty formations, as well as mapping of the fluid contents of the possible reservoir zones was carried out using Interactive Petrophysics software. Fifteen shaly sand bodies were identified. It was observed that, shale correction leads to a significant change in petrophysical parameters. The results obtained indicate that, the Simandoux and Indonesian models used for the study are both suitable for water saturation, and hydrocarbon saturation analysis in shaly sands of this part of the Basin. The porosity results for the Indonesian and Simandoux models gave, respectively 0.14-0.23 and 0.22-0.28, while the hydrocarbon saturation results are 0.650-0.908 and 0.650-0.911 with permeabilities values of 1487.442-8881.697 mD and 1568.532-7451.592 mD for uncorrected and corrected permeability, respectively. Thomas-Stieber model shows that shale distribution in sands of the eastern Niger Delta Basin is mainly structural with few of disperse and laminar ones. Key words: Reservoir rock, Shaly sands, petrophysical parameters, well logs, models.

A laboratory study of complex resistivity spectra for predictions of reservoir properties in clear sands and shaly sands

Abstract To investigate the effect of the application of complex resistivity logging in sand-shale reservoirs, measurements of complex resistivity are performed on core plugs obtained from artificial clear sand samples and shaly sand samples with different clay types and contents in a frequency range of 40 Hz to 15 MHz. This paper discusses the relationship between the complex resistivity values of samples and their porosity, water saturation, salinity, ion type, clay content, and temperature using the Cole-Cole model to fit complex resistivity curves and obtain the model parameters R0 and τ, which represent the resistivity at zero frequency and the time constant respectively. The results show that τ has the same trend as R0 i.e., it decrease as porosity, water saturation, salinity, clay content and temperature increase. Based on the Archie model and Waxman-Smith model, the saturation evaluation model of τ is built. This study also extracts the slope of the real part of complex resistivity and explores the correlation between the slope and permeability. A model of slope can be used to predict permeability, and the model parameters are different for clear sand samples and different shaly sand samples. This study provides strong support for studies of the rock complex resistivity mechanism and the application of complex resistivity logging in oil and gas evaluation.

Consistency Test Calculation Porosity of Logging Resistivity Through the Measurement of Common Resistant in Artificial Core Sample

Research has been done about petrophysics of reservoir as an accumulated hydrocarbon. Every rocks have unequal of resistivity, from this resistivity the porosity (ϕ) quantifiable with using Archie equation. Core sample are made for consistency test calculation porosity of logging resistivity data through the measurement of common resistant in artificial core samples with variation of composite. The result measurement resistivity of shaly sands core samples is 1,19 Ωm consist of clean formation to sandstone 1,29 Ωm, shale 2,58 Ωm and fresh water 0,734 Ωm with measurable porosity is 39,38 % (shaly sands), 19,09 % (sandstone), 42,51 % (shale) and formation factor (F) of shaly sands core samples is 1,62 (shaly sands), 1,75 (sandstone), 3,51 (shale) with this results indicated that decrease in formation factor of shaly sands core samples comparable with increase of porosity of shaly sands core samples. So the data can be used to analyze oil deposit on a reservoir having specific characteristics, so as to increase productivity oil ans natural gas.

Theoretical Approach in Vp/Vs Prediction from Rock Conductivity in Gas Saturating Shaly Sand

Most of study in Oil and Gas Industry are studying Vp/Vs behaviour against hydrocarbon presence in a porous rock. Vp/Vs number is commonly used to model Amplitude Variation against Offset response of a gas sand which allow us be able to discriminate it from the water sand. The model is built in term to match the synthesized Vp/Vs against the observed Vp/Vs which actually correspond to elastic property of porous and fluid saturating rocks. This study is aimed to find correlation between elastic property and conductivity of saturated rocks, especially reservoir in this study is found as a shaly sand unit, a turbidite sand deposit in Kutai Basin, East Kalimantan. The correlation between elastic property and conductivity properties are rarely discussed in many studies, however this study gives a new insight and evidence of how elastic and the inverse of conductivity (resistivity) properties are correlating both ways formulized theoretically with a support from Gassmann and Archie equations. In this study, more realistic condition is accomplished by taking clay mineral into account in sand unit and hence impact to Vp/Vs derivation from resistivity. Furthermore, sand-shale texture is considered important when this study giving a significant discrepancy of how clay mineral is distributed in sand unit and impacted to Vp/Vs and resistivity values. Thomas-Stieber diagram is useful when defining a disperse and/or laminate distribution of shale in the observed porous sand.

New approach for releasing uranium radiation impact on shale content evaluation in shaly sand formations: A case study, Egypt

The total shale volume is a physical parameter that plays a vital role in the evaluation of oil-bearing reservoirs. This study presents a new approach of shale volume calculation using the gamma ray spectrum of only thorium and potassium, avoiding the effect of uranium on gamma ray log (U-free). The calculations of shale volume based on U-free gamma ray log decreased to about 76%, 78%, and 79%, respectively, compared to the calculations based on the total gamma ray in clastic reservoirs in the abovementioned three regions.A new equation was derived to calculate the shale volume in the case of the absence of spectral gamma ray logs. A good agreement was observed between the computed shale volume using (U-free) gamma ray logs and that obtained from the derived equation; showing a variable percentage of 100%, 99%, and 101% of three studied regions in Egypt (Gulf of Suez, Western Desert, and Nile Delta), respectively.To achieve a good quality assurance of this method, the actual shale volumes of rock samples, which were estimated by the hydrometer separation technique, were compared with the calculated values using the new method. A strong correlation was found between them with a correlation coefficient r of 0.93.

A Modified Approach for Volumetric Evaluation of Shaly Sand Formations from Conventional Well Logs: A Case Study from the Talhar Shale, Pakistan

In potential shale-gas basins, due to limited data availability, volumetric evaluation of shaly sand formations is a challenging task for researchers, as well as for exploration and production companies, with the use of conventional well logs. This paper is intended to provide a better understanding of volumetric evaluation in unconventional shaly sand formations. Petrophysical parameters derived from conventional well logs play a significant role in the volumetric estimation of shale. The assessment was performed using numerical equations, well log indexes, and cross-plot analysis. Deep and shallow resistivity logs overlap with each other; this phenomenon indicates that the Talhar Shale in Pakistan can be considered to be an unconventional formation. The average values of shale volume, total porosity, effective porosity, and matrix volume are 29, 16, 12, and 59%, respectively. The Talhar Shale is dominantly characterized by intergranular porosity. It has been observed that at low shale volumes (10–20%), porosities (total and effective), and resistivity measurements (deep, shallow, and microlaterolog), well log signatures have close contents with the shale volume. In contrast, for the remainder of the shale volume, there is significant separation of log signatures. Well log indexes indicate significant responses in 10–20% shale volume zones.

Chargeability of Porous Rocks With or Without Metallic Particles

The chargeability of rocks de nes their ability to reversibly store electrical charges at low frequency (typically below a few kHz). We consider the case of an isotropic mixture of metallic particles embedded into a polarizable porous background composed of mineral grains and pore water. The term metallic is here used in a broad sense involving semiconductors (for instance disseminated pyrite or magnetite), semimetals (e.g., graphite), and metals (copper, steel). The chargeability of such a mixture depends on the chargeability of the background material and the volumetric amount of metallic particles. The chargeability of the background material is in turn salinity dependent and is equal to a universal dimensionless number R = 0.08 (ratio between the normalized chargeability and the surface conductivity) at low salinities. It is given by the ratio of two apparent mobilities, which are actually related to the mobility of the Stern and diffuse layers forming the so-called electrical double layer around the mineral grains. This universal number is saturation and temperature independent. The predictive model for the chargeability of the mixture is compared successfully to variety of experimental and eld data. We show that the polarization of dispersed metallic particles is due to the electrodiffusion of the charge carriers inside these particles. This work can be applied to conventional well-log analysis using the dispersion of the electrical conductivity with the frequency in order to determine the formation properties and accounting for the presence of pyrite in some formations. Our conductivity model appears as an extension of the Waxman and Smits seminal model of shaly sands extending this model to determine the chargeability and the effect of pyrite on both the electrical conductivity and the chargeability.

Modifications to the Kozeny–Carman model to enhance petrophysical relationships

The most commonly used relationship that relates permeability, porosity, grain size and tortuosity is the Kozeny–Carman equation. When it is used to estimate the permeability behaviour versus porosity, the other two parameters (the grain size and tortuosity) are usually kept constant. In this study, we investigate the deficiency of the Kozeny–Carman assumption and the alternative derived equations for the Kozeny–Carman equation is presented, including equations where the grain size is replaced with the pore size with varying tortuosity. We also introduce relationships for the permeability of shaly sand reservoir that answer the approximately linear permeability decreases in the log-linear permeability–porosity relationships in datasets from different locations.