Petrophysical Tools Research Articles

Dealing with unique minerals in petrophysical logs

Most petrophysical equations and methods are designed to deal with hydrocarbons found within mineralogies, such as quartz and feldspars or calcite and dolomite. Petrophysical tools and techniques have also largely been designed to investigate rocks containing these minerals. Hence, when log analysts encounter a field containing unique mineralogies, determining an appropriate petrophysical evaluation process for such unconventional reservoirs can be a challenge. In this paper, we aim to discuss our learnings using two unique case studies. The first is a well which had intersected opalines and logged with conventional modern “western style” tools. The second is a well which has intersected tuffs and volcanics and which was logged with older “Russian style” tools.For opalines, we discuss the potential mineral signatures observed on the well log data and the reservoir potential of the rocks. We find that the unique microporous structure created by opal-CT microspheres/lepispheres, combined with either fracture or matrix-porosity dominant properties, potentially allows for storage of hydrocarbons within the rock. Hence, we hypothesize that opaline reservoirs could be classed as “Low Resistivity Low Contrast” (LRLC) pay and should not be glossed over just because typical hydrocarbon indicators are not seen.For tuffs and volcanics, we first share some of the challenges faced and methods used in conducting modern petrophysical interpretation with data from older Russian-style logs. Again, we discuss the potential mineral signatures observed on the logs and look at properties such as pore throat radii, size, and mineral composition and how that affected reservoir potential. Our findings indicate that the distribution of pore sizes allowed for greater connectivity within the rock, where the pore geometry effects aided in low residual oil saturations.

Formation evaluation utilizing a new petrophysical automation tool and subsurface mapping of the Upper Cretaceous carbonate reservoirs, the southern periphery of the Abu-Gharadig basin, Western Desert, Egypt

The southern periphery of the Abu-Gharadig basin in the Northern Egyptian Western Desert is characterized by some subsurface geological challenges related to the carbonate reservoir's quality, which requires precise petrophysical evaluation and seismic structural interpretation. Therefore, we conducted a subsurface mapping and formation evaluation for the Upper Cretaceous carbonate reservoirs in the Southwest Abu Sennan (SWS) area utilizing seismic reflection profiles and borehole geophysical data. Seismic mapping of the Upper Cretaceous carbonate reservoirs (Abu Roash (AR)/B,/D, and/F) revealed 3-way folds with NE-SW trends divided by NW-SE normal fault trends presenting significant chances for exploration. These closures were filled by hydrocarbons generated from the Jurassic source rocks. Formation evaluation was performed using the new petrophysical tool “Gaialog” which was coded using Python. Petrophysical parameters for the recognized net pay intervals of AR/B, AR/D, and AR/F carbonate reservoirs showed that the effective porosity (φeff: Phie) and the hydrocarbon saturation (Sh) increases towards the East to Southeast direction while the water saturation (Sw) increases to the Northwest of the study area. The highest net pay and the effective porosity were found in the Eastern part of the study area. The study procedures can be applied in neighboring areas to evaluate and understand similar reservoirs.

NMR T2 CUT OFF: WHICH ONE IS TO BE USED FOR APPLICATION?

Recent developments in petroleum industry have been witnessing the surge of the use of nuclear magnetic resonance (NMR) log. Despite some remaining problems the NMR technology appears to gain more acceptance as petrophysical tool for evaluating reservoir quality. Comprehensive formation evaluation requires determination of irreducible fluids, movable fluids, and permeability. However, rock heterogeneity introduces complexity in any formation evaluation activities. This can also cause problem for NMR log interpretation. In the presence of clays the most commonly used T2 cut off values, a constant value throughout a formation, seem to eventually yield inaccurate irreducible water saturation estimates, as well as other output such as permeability. This study focuses at finding a solution for finding the best way of choosing the most representative T2 cut off value to be used in NMR log interpretation. This is indeed a common pressing problem for heterogeneous formation rocks such as in the case of Tirrawarra sandstones used in this study. The main part of the study is devoted to comparison between the use of single averaged T2c value and establishment of empirical correlations enabling the provision of T2c for any level of heterogeneity (i.e. various levels of shaliness). The study however surprisingly shows that, in spite of the theoretical soundness of the empirical correlations established, simple averaging of T2c values yielded by a reliable method proves itself adequate. This conclusion therefore helps considerably in reducing complexity in NMR log interpretation.

Effective elastic properties of porous rocks with fluid-filled vugs

The problem of determination of the effective elastic properties, particularly, the velocity and attenuation of the compressional wave propagating in porous rocks containing fluid-filled vugs is considered. Usually the correct interpretation of double- or triple-porosity formations using sonic logs is a complex problem, even nowadays with the use of the most advanced inversion algorithms and the contribution of other petrophysical tools. In this work, the proposed model considers spherical inclusions filled with viscous or ideal fluids aimed to represent geological vugs. This approach also considers the cases of “open” and “closed” interfaces at the boundary between the porous rock and the vug. To describe the propagation of elastic waves in porous rocks, the well-known Biot's theory is implemented. The calculations were fulfilled for the incidence of plane compressional harmonic waves. As the first step of performed calculations the so-called one-particle problem is solved. Then, the first order (single-scattering) approximation is applied to calculate the effective wave number of elastic waves propagating in a poroelastic rock containing sets of randomly distributed vugs. The results reported here show that the hydrodynamic effects associated with the fluid filtration at the boundaries between the vugs and the porous rock at the scale of the incident compressional wave, lead to significant frequency dispersion of the effective elastic wave velocity and its correspondent Q-factor. These hydrodynamic effects on the elastic properties are clearly appreciated at the sonic log frequency range. From the findings of this paper, it can be sustained that the elastic response of the fluid viscosity in the vugs is not so significant. This implies that it is possible to use the simple model of an ideal fluid in the vugs.

Reservoir characterization and 3D modeling of the Aptian Alamein Formation in North Razzak area (North Western Desert, Egypt)

Improving exploration and development techniques of fossil fuels are essential for continuous reserves development. Although there are many oil discoveries in the Razzak Area (North Western Desert, Egypt), there are also many dry wells. Therefore, the tectonic setting and reservoirs characterization of the study area has to be fully understood. Twenty 2D highly filtered stack zero-phase seismic sections and logging data of four wells were analyzed. According to seismic sections and structure contour maps (both time and depth), there is one major structural high (horst). It is a part of the regional Jurassic rift system. The NE Jurassic rifts continued during the deposition of the Early Cretaceous strata as growth faults and have been rejuvenated or continued during the closure of the Neotethys Ocean. During the Late Cretaceous, the compressional stress resulting from the collision between African and Eurasian plates has led to the inversion of the Razzak basin, where some segments of the main faults are transformed from normal to reverse and the hanging walls formed plunging drag fold, which was dissected by a set of NW-SE normal faults. Four prospective closures in the Razzak Field were highlighted. Based on integrated petrophysical tools (Gamma Ray, Sonic Log, Resistivity Deep, Neutron Porosity, and Bulk Density) in four wells (NRZK-1, NRZK2, NRZK-3, and NRZK-4), the Aptian Alamein Formation (mainly dolomite) was interpreted to be a good reservoir and can be subdivided into two zones (Upper Alamein and Lower Alamein) with different reservoir quality. In addition, 3D structure, facies, and petrophysical models were built based on integrated geological and petrophysical data. The results indicated that integrating both seismic profiles with logging data, even from a small number of wells, is highly valuable in evaluating reservoir quality and defining future prospective.

Magnetic properties related to hydrothermal alteration processes at the Escondida porphyry copper deposit, northern Chile

Fluid–rock interaction related to the circulation of hydrothermal fluids can strongly modify the physicochemical properties of wall rocks in porphyry Cu deposits. These processes can also produce compositional and textural changes in ferromagnetic minerals, which can be quantified using magnetic methods. In the Escondida porphyry Cu deposit of northern Chile, each hydrothermally altered lithology is characterized by a discrete assemblage of Fe–Ti oxide minerals. These minerals have distinctive bulk magnetic susceptibility (K bulk), temperature-dependent magnetic susceptibility, and magnetic hysteresis parameters. Selectively altered rocks (i.e., potassic and chloritic alteration types) exhibit the highest K bulk values (>3.93 × 10−3 SI units), and their hysteresis parameters indicate multidomain magnetic mineral behavior. This suggests that these rocks are composed of the coarsest magnetic grain sizes within the deposit. Optical analyses and susceptibility–temperature curves confirm that the magnetic signals in selectively altered rocks are mainly carried by secondary magnetite. In contrast, pervasively altered rocks (i.e., quartz-sericite and argillic alteration types) exhibit low K bulk values (<1.93 × 10−4 SI units) and contain smaller pseudo-single domain magnetic grain assemblages. This is consistent with the destruction and/or reduction in size of magnetite under acidic conditions. The results therefore demonstrate a genetic relationship between the hydrothermal alteration processes, Fe–Ti oxide minerals, and magnetic properties of the wall rock in the Escondida deposit. These magnetic methods can be considered a sensitive and efficient petrophysical tool for the identification and semi-quantification of alteration assemblages, and facilitating the recognition and mapping of discrete hydrothermal zones during exploration and operation of porphyry Cu deposits.

A Complete Petrophysical-Evaluation Method for Tight Formations From Drill Cuttings Only in the Absence of Well Logs

Summary The amount of tight-formation petrophysical work conducted at present in horizontal wells and the examples available in the literature are limited to only those wells that have complete data sets. This is very important. But the reality is that in the vast majority of horizontal wells, the data required for detailed analyses are quite scarce. Petrophysical evaluation in the absence of well logs and cores can now be considered owing to the possibility of measuring both the permeability and porosity of drill cuttings. This is essential because the application of the successive correlations used throughout the paper is based on porosity and permeability data. To try to alleviate the data-scarcity problem, a new method is presented for complete petrophysical evaluation derived from information that can be extracted from drill cuttings in the absence of well logs. The cuttings data include porosity and permeability. The gamma ray and any other logs, if available, can help support the interpretation. However, the methodology is built strictly on data extracted from cuttings and can be used for horizontal, slanted, and vertical wells. The method is illustrated with the use of a tight gas formation in the Deep basin of the western Canada sedimentary basin (WCSB). However, it also has direct application in the case of liquids. The method is shown to be a powerful petrophysical tool because it allows quantitative evaluation of water saturation, pore-throat aperture, capillary pressure, flow units, porosity (or cementation) exponent m, true-formation resistivity, and distance to a water table (if present). Also, the method allows one to distinguish the contributions from viscous and diffusion-like flow in tight gas formations. The method further allows the construction of Pickett plots without previous availability of well logs, and it assumes the existence of intervals at irreducible water saturation, which is the case of many tight formations currently under exploitation. It is concluded that drill cuttings are a powerful direct source of information that allows complete and practical evaluation of tight reservoirs in which well logs are scarce. The uniqueness and practicality of this quantitative procedure originate from the fact that it starts only from the laboratory analysis of drill cuttings—something that has not been performed in the past.

Petrophysical characterization of Chinese coal cores with heat treatment by nuclear magnetic resonance

For the past decades the nuclear magnetic resonance (NMR) technology has gained acceptance as a petrophysical tool for evaluating reservoir properties. Comprehensive reservoir evaluation requires determination of irreducible fluids, movable fluids and permeability. Although the NMR petrophysical properties of coals have been studied for decades, the impact of heat on these properties (pore size distribution, pore structures, porosity and permeability) has not yet been systematically investigated. However, these are key properties for coalbed methane (CBM) generation and production. Therefore, they may have significant implications for the effects of heat from geothermal dynamics and magma intrusion on CBM concentration and transport in coals with different ranks. Thus, NMR experiments for samples treated at different temperatures (from 25°C to 375°C) were designed to study the variation of petrophysical properties of three Chinese coal cores with different ranks. Results show that NMR transverse relaxation (T2) distributions of the water saturated cores strongly relate to the coal pore structure and coal rank. Furthermore, based on T2 cutoff time method, five models for calculating the permeability of coals to water were evaluated. The results show that the Schlumberger Doll Research (SDR) model and its improved model provided the best estimation among the five models because these two models are generally able to represent the matrix permeability of the coal, based on the comparison between the results from measured gas permeability and NMR permeability models. Further calculations indicate that the porosity of all three different rank coals have an increasing trend with exposure to temperature, but with different increments for these coals. The low-volatile bituminous coal has the largest increment (9.44%), which is an improvement of more than 200% from its original porosity (4.02%). While the permeability has no similar trend for these three rank coals after heat treatment due to the strong heterogeneity of pore structure in coals. The results may suggest complex microfractures widths change for forming/closing at different heating stages.

Quantification of shale volume from borehole logs calibrated by SEM analysis: a case study

The presence of mixed carbonate and siliciclastic rocks complicates the choice of appropriate petrophysical tools for shale volume estimation. In this case study, conventional uranium-corrected gamma-ray and spectral gamma-ray logs were initially used for shale volume estimation. The results, however, were not supported by the nuclear magnetic resonance (NMR) log. Significant discrepancies were found in the reservoir where a considerable shale volume was estimated from the gammaray logs. Scanning electron microscope (SEM) analysis verified that potassium is present in clay and as potassium feldspar. Knowing the proportion of minerals from SEM analysis allows calibration of the spectral gamma-ray log for the potassium content of the clay at selected depths. Calibrated spectral gamma-ray values at the selected depths and the uniformity of the spectral gamma-ray logs are used to correlate the spectral gamma-ray logs over the intervals between the selected depths. The corrected spectral gamma-ray logs were used to recalculate shale volume, and resulted in a significantly reduced estimate. Validation of the result with the NMR log confirms the SEM and gamma-ray calibrated shale volume estimates, and suggests that the NMR log is a valuable tool for shale volume evaluation.

Determination of NMR T2 cut off for ductile, low permeability shaly sandstone

For the past decades nuclear magnetic resonance (NMR) technology has gained acceptance as petrophysical tool for evaluating reservoir quality. Comprehensive formation evaluation requires determination of irreducible fluids, movable fluids, and permeability. The presence of clay, their occurrences and distributions, however, in some reservoir rocks tends to introduce complexity in any formation evaluation activities. This can also cause problem for NMR log interpretation. In the presence of clays the most commonly used T2 cut off values, a constant value throughout a formation, seem to eventually yield inaccurate permeability estimates. Therefore, NMR measurements should be integrated with other measurements from conventional cores for a comprehensive formation evaluation, in which T2 cut off may vary for reservoir with different reservoir qualities. This paper presents results of a study that focuses on NMR measurements on Tirrawarra shaly sands taken from 3 wells situated in Cooper Basin, South Australia. The study suggests that the T2 cut off values for the samples vary significantly in order for NMR-derived irreducible water to match core-derived irreducible water. This is also true for NMR-derived permeability estimates when compared to measured permeability values. Comparisons between estimates produced using the normally used `constant T2 cut off' and the suggested `varied T2 cut off', as well as their effect on formation evaluation, are also discussed. In general, the results highlight the need to study T2 cut off values more directly for specific reservoir rocks before their practical uses in the field.

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.

Pore microgeometry analysis in low-resistivity sandstone reservoirs

The objective of this work is to analyse the pore microgeometry and its effect on petrophysical properties in six low-resistivity sandstone reservoirs by combining a 2D quantitative petrographic image analysis (PIA) and 3D petrophysical tools. The classic petrophysical tools enable the measurement of different classic reservoir properties such as specific surface area, average pore diameter, pore size distribution, macroporosity and microporosity, capillary pressure versus saturation, pore chamber–pore throat diameter ratio, electrical properties and permeability. The petrographic image analysis quantifies pore microgeometry in more than four orders of magnitude, from submicron to millimeter scale. Chloritic low-resistivity sandstones show dual porosity structure defined as chloritic texture. The pore microgeometrical parameters measured by petrographic image analysis allow one to model different reservoir properties such as capillary pressure, permeability and electrical behaviour. The results obtained in these models show that pore microgeometry plays an important role in the physical properties of low-resistivity sandstone reservoirs.

Application of NMR Logging to Reservoir Characterization of Low-Resistivity Sands in the Gulf of Mexico1

Nuclear magnetic resonance (NMR) technology from laboratory data and well logs is rapidly gaining acceptance as a petrophysical tool for evaluating reservoir quality. The evaluation of laboratory NMR data as a core analysis technique shows that NMR relaxation time distributions match independent estimates of pore-size distributions. These other pore-size estimates come from grain-size analyses, pore-throat distributions from mercury porosimetry, thin-section petrography, and permeability values. Irreducible water-saturation estimates from NMR-based pore-size distributions also correspond well with independent measures of irreducible water from special core flood tests. In this study, we look at the relaxation time distributions extracted from laboratory and downhole NMR measurements to determine pore geometry and volumetrics within a reservoir. This understanding leads to a better overall reservoir characterization. Both core and log NMR data are used to demonstrate that there is a direct connection between NMR relaxation time distributions and the fundamental property of pore size in sandstones. This description of pore-size distributions allows us to estimate permeability and irreducible water saturation. Additionally, the NMR logs accurately characterize the NMR core (lab) measurements and provide important information that enhances the description of low-resistivity pay.

The Role of Geology in the Behavior and Choice of Permeability Predictors

Summary For effective flow-simulation models, it may be important to estimate permeability accurately over several scales of geological heterogeneity. Critical to the data analysis and permeability prediction are the volume of investigation and sampling interval of each petrophysical tool and how each relates to these geological scales. We examine these issues in the context of the As Sarah Field, Sirte Basin, Libya. A geological study of this braided fluvial reservoir has revealed heterogeneity at a series of scales. This geological hierarchy in turn possessed a corresponding hierarchy of permeability variation. The link between the geology and permeability was found to be very important in understanding well logs and core data and subsequent permeability upscaling. We found that the small scale (cm) permeability variability was better predicted using a flushed-zone resistivity, Rxo, tool, rather than a wireline porosity measurement. The perm-resistivity correlation was strongest when the probe permeabilities were averaged to best match the "window size" of the wireline Rxo. This behavior was explained by the geological variation present at this scale. For the larger scale geological heterogeneity, the production flowmeter highlighted discrepancies between flow data and averaged permeability. This yielded a layered sedimentological model interpretation and a change in averaging for permeability prediction at the bedset scale (ms-10 × ms).