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Актуальность. Все отечественные стандарты по проведению лабораторных исследований на образцах керна пород нефтяных и газовых пластов предписывают произвести его очистку от углеводородов с помощью экстракции. Очистка образцов керна входит в обязательный этап подготовки к основным видам лабораторных исследований. Для этого используются специальные экстракционно-дистилляционные аппараты с применением различных органических растворителей. Образцы керна, помещенные в аппараты, в течение длительного времени проходят многократные циклы очистки с высокотемпературным воздействием. Такой подход к подготовке образцов керна является традиционным и применяется как для стандартных, так и для специальных исследований. Однако экстракция приводит к искаженным представлениям о естественной смачиваемости поверхности породы, которая подвергается изменению и, как правило, гидрофилизируется. В связи с этим важно провести оценку смачиваемости породы на различных этапах подготовки образцов керна - до и после процедуры экстракции. Цель: разработка методики прогноза величины смачиваемости образцов керна до экстракции от углеводородов с применением статистических методов исследования. Объекты: образцы керна задонских отложений (D3zd) Восточно-Ламбейшорского месторождения, артинские (P1ar) и ассельско-сакмарские (P1a+s) отложения Ярейюского месторождения. Методы: метод Амотта (Амотт -Харви), статистические методы. Результаты. С помощью проведенного комплекса лабораторных исследований с использованием различных статистических методов была разработана методика прогноза значений показателя смачиваемости по нефти до экстракции на основе фильтрационно-емкостных свойств образцов керна. The relevance. All domestic standards for laboratory studies of core oil and gas reservoirs prescribe to clean it from hydrocarbons by extraction. Cleaning of core samples is included in the stage of preparation for the main types of research. For this, a wide range of different solvents and special extraction and distillation apparatuses are used. Core samples placed in the apparatus undergo multiple cleaning cycles for a long time with high-temperature exposure. This approach to the preparation of core samples is traditional and is used for both standard and special studies. However, extraction leads to a distorted understanding of the natural wettability of the rock surface, which is subject to change and, as a rule, hydrophilizes. In this regard, it is of scientific and practical interest to assess rock wettability at various stages of sample preparation - before and after the extraction. The main aim: development of a methodology for predicting the wettability of core samples before extraction from hydrocarbons using statistical research methods. Objects: core samples of the Zadonskaya deposit (D3zd) of the Eastern Lambeishor field, Artinskaya (P1ar) and Assel-Sakmarskaya (P1a+s) deposits of the Yareyu field. Methods: Amott (Amott-Harvey) method, statistical methods. Results. With the help of a set of laboratory studies using various statistical methods, a methodology was developed for predicting the values of the wettability index for oil before extraction based on the porosity and permeability properties of core samples.

Several sets of Paleozoic tight reservoirs are developed in the Central Uplift of the South Yellow Sea Basin. A qualitative analysis of the microscopic pore structure of the tight reservoir rocks was carried out through cast thin slice and scanning electron microscopic image observation. Based on reservoir petrophysical properties, thirty core samples in the Central Uplift of the South Yellow Sea Basin were selected for high-pressure mercury intrusion (HPMI) analysis, which was then combined with fractal calculation to classify and evaluate the tight reservoirs. The analysis of the HPMI curves and related parameters shows that the Paleozoic tight reservoirs can be divided into three types: Type-A, Type-B and Type-C. Type-A sandstone reservoirs contain pores with size mostly ranging between 0.01 and 0.1 μm, followed by pores with size range of 0.001–0.01 μm, and relatively fewer pores larger than 0.1 μm. The Type-B reservoirs are carbonate rocks with extremely heterogeneous pore size distribution, which is closely related to the development of dissolution pores and microfractures. Type-C sandstone reservoirs are dominated by nanopores and submicron pores that distribute more heterogeneously than pores in Type-A reservoirs. The pore distribution in sandstone reservoirs shows significant fractal characteristics and is closely related to the pore size. The heterogeneity of nanopore distribution has a negative correlation with porosity and median pressure and a relatively weak correlation with permeability. Our study has important implications for petroleum exploration in the South Yellow Sea Basin.

Analysis of reservoir sensitivity to velocity, water, salt, acid, alkali and stress is critical for reservoir protection. To study the tight sandstone reservoir sensitivity at different formation depths (effective stress) and formation water conditions (pH, salinity, and fluid velocity), a series of dynamic core flow tests under different pH, salinity, acid, and effective stress conditions were performed on samples from tight sandstone reservoirs of the Upper Triassic Yanchang 8 (T3y8) Member and conventional reservoirs of the Middle-Lower Jurassic Yan'an 9 (J1-2y9) Member in the Ordos Basin. The results indicate that, compared with the conventional reservoirs, the tight sandstone reservoirs are more sensitive to velocity and stress, less sensitive to water, alkali and salinity, and respond better to acid fracturing. In addition, the critical conditions (salinity, velocity, pH, and stress) for pumping drilling, completion, and fracturing fluids into tight sandstone reservoirs were investigated. A combination of scanning electron microscopy coupled with energy-dispersive spectrometry (SEM-EDS), cathodoluminescence (CL), casting thin section (CTS) and nuclear magnetic resonance (NMR) images, high-pressure mercury injection capillary pressure (MICP) measurements as well as X-ray fluorescence spectral (XRF) analyses were employed to analyze the damage mechanisms of the conventional reservoirs (J1-2y9) and tight sandstone reservoirs (T3y8) caused by fluid invasion. The results suggest that reservoir sensitivity is primarily conditioned by the composition of detrital components and interstitial fillings, petrophysical properties, pore-throat structure, and diagenetic facies. All these factors control the sensitivity types and extent of the reservoirs. Our results indicate that the poorer the reservoir physical properties, the stronger the reservoir heterogeneity and sensitivity, implying that tight sandstone reservoirs are more susceptible to changes in fluids than conventional reservoirs. This study offers insights into the reservoir damage types and helps to improve the design and implementation of protection measures for tight sandstone reservoir exploration.

Background: It is widely acknowledged that carbon dioxide (CO 2), a greenhouse gas, is largely responsible for climatic changes that can lead to warming or cooling in various places. This disturbs natural processes, creating instability and fragility of natural and social ecosystems. To combat climate change, without compromising technology advancements and maintaining production costs at acceptable levels, carbon capture and storage (CCS) technologies can be deployed to advance a non-disruptive energy transition. Capturing CO 2 from industrial processes such as thermoelectric power stations, refineries, and cement factories and storing it in geological mediums is becoming a mature technology. Part of the Mesohellenic Basin, situated in Greek territory, is proposed as a potential area for CO 2 storage in saline aquifers. This follows work previously done in the StrategyCCUS project, funded by the EU. The work is progressing under the Pilot Strategy, funded by the EU. Methods: The current investigation includes geomechanical and petrophysical methods to characterise sedimentary formations for their potential to hold CO 2 underground. Results: Samples were found to have both low porosity and permeability while the corresponding uniaxial strength for the Tsotyli formation was 22 MPa, for Eptechori 35 MPa and Pentalofo 74 MPa. Conclusions: The samples investigated indicate the potential to act as rock caps due to low porosity and permeability, but fluid pressure within the rock should remain within specified limits; otherwise, the rock may easily fracture and result in CO2 leakage or/and deform to allow the flow of CO 2. Further investigation is needed to identify reservoir rocks as well more sampling to allow for statistically significant results.

Extensive reviews and cross-comparison studies are essential to analyze the emerging developments in a specific field of research. In the past decade, hydrocarbon exploration and exploitation from the shale reservoirs have been the most discussed and researched area around the globe. A dramatic development in shale formations became the game-changer, especially in the US. On the other hand, Artificial Intelligence (AI) and Machine Learning (ML) are playing an important role in the rapid development in all the industries through automating most of the routine operations. The oil industry is also getting equal benefits of AI and ML for the reservoir development planning and its operational accuracy through a series of automated systems. For the field development, computerized static and dynamic simulation models are generated based on several Petrophysical and Geomechanical properties gathered through different resources that are quite a time taking and expensive. AI and ML have made this process much easier, faster, and economical by means of learning through uncounted experiences from already explored and developed reservoirs, their rock properties, and the cross-ponding fluid flow behavior under different circumstances and hence, predicts accordingly. This article provides a comprehensive literature review in the area of AI and ML application to model Petrophysical and Geomechanical properties using different approaches and algorithms. Also, a systematic publication counts in each field of subject study per year in different literature databases are presented that infect reflects the trending interest in this subject. Finally, multiple AI and ML techniques are discussed in detail that has been tested in the last decade for the sake of achieving more accuracy in Petrophysical and Geo-Mechanical simulation models.

The first sparse 3D hardrock seismic survey at Olympic Dam (OD) mine was acquired during June to August of 2022. OD is an Iron-Oxide Copper Gold (IOCG) deposit in South Australia and is one of the largest known copper deposits and the single largest uranium deposit in the world. This property-wide seismic survey at OD was designed to answer four technical questions defined in a 3D seismic feasibility study focused on seismic imaging of IOCG-type geology, as well as identify operational challenges with seismic acquisition across a busy mine site. This adaptation of modern-day hardrock seismic methodologies over an ore deposit represents the largest to date of any hardrock seismic application for BHP and will accelerate resource characterisation and the targeting of deep drillholes. Outcomes of this sparse 3D survey inform several decision points for a full 3D seismic survey at OD., Open-Access Online Publication: May 29, 2023

Iron oxide copper-gold (IOCG) systems form in a range of lithologies, including variably metamorphosed felsic and mafic volcanics, carbonates and siliciclastic sedimentary rocks. The chemistry, porosity and permeability of the host rocks control the reactive potential of mineralising fluids. They form across a range of crustal rheologies, from mid-crustal (ductile) to upper-crustal (brittle) conditions. IOCGs are focussed via a range of structural controls, including permeable strata, shear zones, fault jogs, splays and intersections and breccia pipes. The mechanism of fluid localisation controls geophysical zonation (e.g., planar vs concentric zonation). IOCGs also comprise a spectrum of mineralisation assemblages from reduced, pyrrhotite-dominant examples to magnetite-, and more oxidised, hematite dominant deposits. Such Fe-bearing minerals have contrasting magnetic, density and conductivity properties, and therefore redox/pH and geophysical properties are linked. The interaction of major controls, including host rock chemistry, rheology, structural controls, and redox/pH conditions, define the style of geophysical anomaly associated with an IOCG system. The Cloncurry mineral system comprises a spectrum of deposit styles, not observed across the other major IOCG provinces, and provides an excellent window into the array of possible geophysical signatures. This study synthesises findings of Cloncurry METAL, a three-year study which collected integrated petrophysics, mineralogy and structural data from almost every major deposit/prospect in the Cloncurry district. It provides petrophysical properties of the host rocks and mineralised lithologies across the mineral system and explore some of the ways variations in host rock chemistry and rheology, structural controls and redox/pH zonation interact to form contrasting geophysical targets., Open-Access Online Publication: May 29, 2023

Despite our reliance on geophysical surveying in mineral exploration, we have a relatively poor understanding of the link between petrophysical properties (at the scale of 100 metres). Drilling campaigns is critical because it bridges the two end-member scales and constitutes rocks that can be sampled and from which observations can be made. There are a range of techniques for measuring rock properties in drill holes and on drill core that vary in cost, time, data quality and resolution. A key question for explorers is: What are the optimum data to collect (and at what resolution) to adequately constrain and make geological sense of our geophysical models? A complicating factor is that petrophysical properties are not routinely collected and reconnaissance techniques (e.g., handheld MagSus) provide only part of the picture. This study sets out to define a methodology for petrophysical sampling of mineralised rocks using three mineralised drill holes from separate deposits in the Cobar Province. The inspected core are from the structurally controlled New Cobar deposit and two skarn-type deposits, Nymagee and Hera. New Cobar sits nearby to the magnetic high of the Great Cobar deposit. It contains both magnetite and pyrrhotite; however, not all the pyrrhotite is magnetic, which results in a relatively small geophysical signal. The Nymagee anomaly is a strong dipole and holds a remanence component. The deposit preserves both magnetite and pyrrhotite. At Hera, magnetite is completely absent and the deposits is often described as non-magnetic. As shown in this study, all three deposits do have some magnetic susceptibility associated with, or in the vicinity of, mineralisation. Natural gamma radiation response varies and conductivity responses are locally observed (scale, Open-Access Online Publication: May 31, 2023

A sedimentary complex from Bedout Basin in North West Shelf (NWS) of Australia has been analysed using petrophysical, geochemical, petrography and chemostratigraphy data to assess the occurrence of sulfidation process. Sandstone and clay layers are the dominant lithologies with thicknesses varying in the magnitude of meter scale from Lower to Upper Tertiary. The existence of pyritisation in sandstone sediment indicates correlation with porosity and permeability with higher contents in porous and permeable sandstones. The Lower Tertiary sandstones show porosities and permeabilities on the order of ~2 to 21 % and ~15 md to 5 d, respectively. We interpret the higher volume of pyritisation observed in sandstone units compared to claystone and shales is related to sediments burial processes, increased burial temperature and higher porosity and permeabilities of these units. Integrated Multi-Mineral petrophysical interpretation of Gamma Ray, Density, Neutron, Resistivity and Spectral Natural Gamma Ray logs show indications consistent with our observations from processed image log. These results can be used to identify and quantify the pyritisation in sandstone sediments. The discrimination between primary and secondary pyritisation can be inferred through petrography. Chemostratigraphy interpretation results integrated with petrophysical data also provide elemental and mineralogical boundaries which give insights into identifying the alteration and oxidation zones. This integrated approach can be applied to identify pyritisation processes which suggest the existence of iron, and more importantly within an environment of dissolved sulphides which can control the distribution of mineralisation - copper and gold for example., Open-Access Online Publication: May 29, 2023

Greenfield mineral exploration undercover presents a number of challenges. In the East Albany-Fraser Orogen, when faced with the possibility of 300-700m of cover and very little previous exploration, any available data is valuable. Collection of petrophysical data is a cost-effective method to optimise the information in the available drilling with three main benefits: Firstly, an understanding of the physical properties of the cover sequence of the Eucla Basin, the Madura and Loongana Formations and the underlying basement will aid in the geophysical modelling and development of the mapping and targeting program. Secondly, when the petrophysical data from a drill hole is effectively integrated with the mineralogy, geochemistry and observed lithology, a greater understanding of the geological controls of the petrophysical properties can be observed and the processes that are influencing them inferred. Finally, with comprehensive integration of these datasets, will significantly increase our confidence in the source, validity and interpretation of the geophysical responses. A study was undertaken utilising Geological Survey of Western Australia (GSWA) Exploration Incentive Scheme (EIS) open file drillhole data from East_Fraser Orogen. Peterophysical data were collected on the available core and new acquired drillholes and this included magnetic susceptibility, dry bulk density, apparent porosity, grain density, pwave velocity, acoustic impedance galvanic resistivity, chargeability and inducted conductivity. All drill holes reached basement, a few holes had cover that could be sampled, all holes had different levels of geochemical assaying, and petrography was available for some of the holes. The results of the integration of the petrophysical data with the mineralogy, geochemistry and observed lithology were many. They included a strong correlation between the dense observations in the core and lithological and mineralogical changes in the basement and a better understanding of the cover and the source and nature of its conductivity response., Open-Access Online Publication: May 29, 2023

In this paper we give an example from the Fortitude North prospect in the Kurnalpi Terrane of the eastern Yilgarn Craton, where the integration of geochemistry with borehole petrophysics can be used to identify lithological units, infer geological processes (e.g., magmatic differentiation, alteration and weathering) and constrain geological and geophysical models of the prospect. We use major and immobile trace element concentrations to discriminate between primary lithologies and identify differentiation trends in the mafic magmatic units. Density and seismic velocity measurements show broad correlation with primary rock types, with unaltered dolerite tending to have higher density and velocity compared to basalts and altered rocks. Magnetic susceptibility measurements are used to corroborate geochemical differentiation trends, specifically magnetite fractionation in dolerite units. A range of gold pathfinder and chalcophile elements are used to identify hydrothermal alteration related to gold mineralisation. Integrating geochemistry and petrophysics at drillhole- and prospect-scales helps to constrain important geological processes and demonstrates how those processes can be interpreted from geophysical data sets., Open-Access Online Publication: May 29, 2023

The Ravensthorpe nickel laterite deposits in Western Australia are defined by different regolith layers that must be mined and processed separately. A surface caprock layer is waste material (and used as road base), beneath which are limonite and saprolite layers that are sent to separate processing streams. As the regolith grades into saprock below this, the mineral resource falls below an economic level. Within the limonite and saprolite, further variations in material properties affect processing results, including during the beneficiation, or physical upgrading stage. The boundaries between these layers are geometrically complicated, such that very close-spaced drilling would be required to define them to an accuracy relevant to mining. In an effort to mitigate wider drillhole spacing, different geophysical techniques have been trialled to trace boundaries between drill holes. Any technique must be rapid, with high spatial resolution, and preferably continuous, in order to cover the many kilometres of resource drilling and eventually be deployed in a mine pit during operation. Petrophysical logging serves as both a check on the surface geophysics and a potential avenue for predicting material behaviour where multi-element geochemical assays alone have failed. Conductivity and gamma logging, for example, characterise discrete zones that are not represented in the geochemistry or visual logging. Active and passive seismic, electromagnetics, and ground-penetrating radar show variable success in mapping different interfaces. Ground EM demonstrates the most promise, mapping both resistive caprock and a conductive, clay-rich, upper limonite layer that is also indicated by the petrophysical logging., Open-Access Online Publication: May 22, 2023

3D geocellular modeling is increasingly essential in the petroleum industry; it brings together all petroleum disciplines, and it is commonly used in simulation and production forecast. However, modeling slope and deep-water turbidite reservoirs using conventional modeling methods pose a significant challenge due to the structural complexity and thin-beds associated with these reservoirs. Through the innovative modeling technology of PaleoScan, the reservoirs in Sub member 3 of the third member of the Shahejie Formation are modeled to understand the structural framework. The resulting model is populated with petrophysical properties i.e., porosity and permeability to predict their lateral and vertical distribution within these sandstone reservoirs. The study suggests that the reservoir in the highstand system tract (HST) is characterized by the clinoforms configuration framework. The reservoir is highly faulted mainly in the northern and southeastern parts of the depression. The sedimentary layers are deposited across the slope and downlapping, thinning, and terminating toward to the west. The two isochore surface maps reveal sediment thickness variation and depositional trends within each individual depositional layer. The zones or areas that corresponds to low values on the thickness maps suggest minor uplifts associated with intensive faulting in the Eocene period. These topographical highs played a fundamental role in distributing the sediments delivered to the basin from distant sources. The maps reveal that sediments that filled the basin appear to come from different source points, primarily delivered from the north, southeast, and northeast of the basin with varying depositional trends. The modeled porosity and permeability indicate that the delta fed turbidite reservoirs are characterized by medium to high porosity values of 10–20% and low to medium permeability values of 30-410mD, respectively. The porosity values increase to the southeast and toward the basinwards (west) while permeability varies within the individual sedimentary layers. The distribution of porosity and permeability is not uniform vertically. This suggests the presence of mixed none-reservoir layers with locally and periodically deposited sandstone reservoirs within the stratigraphic during rapid delta progradation. The HST is characterized by six different delta progradation cycles; each phase produced locally deposited lacustrine turbidite sandstones in the basin, which are essential reservoirs in this Formation. The innovative PaleoScan interpretation technology has successfully created a high-resolution 3D reservoir model of this complex geology-such innovative technology is vital to similar complex geology globally.

This study evaluates variations in petrophysical properties within a mixed alluvial to lacustrine carbonate system (Miocene, Madrid Basin, Central Spain). The transition from alluvial environments to lake margins settings displays a shift from alluvial, siliciclastic red sandstones and mudstones to palustrine–lacustrine mudstones to packstones. Fluctuations in lake‐water level enabled land plants to occupy the lake margins during periods of low lake levels. The palustrine carbonates include features like pseudo‐microkarst, nodular and mottled limestones; the lacustrine deposits include enlarged root cavities, desiccation cracks and channel bodies. Scarce fresh water biota comprises charophytes, gastropods and ostracods. The sediments possess high natural, irregular varying, gamma‐ray values at the alluvial–lacustrine transition, and low, but constant values at full lacustrine sites. Acoustic properties agree with lithological variations within individual facies. Porosity is the most important parameter influencing P‐wave and S‐wave velocities. The scatter in the velocity–porosity relationship links to the porosity type; macro‐porosity or microporosity. The wide range of pore types and pore sizes results in a weak porosity to permeability relationship for the carbonate‐dominated rocks with low permeability for microporous and high permeability for macro‐porous carbonates. The sandstones (probably only inhibiting interparticle porosity), and to a lesser extent the sandy wackestones to packstones, show quite a strong relationship between porosity and permeability. Elastic properties of mixed alluvial–lacustrine deposits (this study) and marine deposits (literature data) overlap as variations in pore structures and porosity values are similar. Only 16% of the marine and lacustrine carbonate sediments display Equivalent Pore Aspect Ratio values above 0.2. In travertine deposits, 83% of the samples exceed Equivalent Pore Aspect Ratio values above 0.2, which highlights that travertine deposits are dominated by larger Equivalent Pore Aspect Ratios compared to lacustrine and marine carbonate deposits. Travertines display other rock frameworks with different pore types, pore distribution and amount of porosity.

Multimineral log analysis is a quantitative formation evaluation tool for geologic and petrophysical reservoir characterization. Rock composition can be estimated by solving equations that relate log measurements to the petrophysical endpoints of minerals and fluids. Due to errors in log data and uncertainties in petrophysical endpoints of constituents, we have used effective medium models from rock physics as additional independent information to validate or constrain the results. We examine the Voigt-Reuss (VR) bound model, self-consistent approximation (SCA), and differential effective medium (DEM). The VR bound model provides the first-order quality control of multimineral results. We first show a conventional carbonate reservoir study with intervals in which the predicted effective medium models from multimineral results are inconsistent with measured elastic properties. We use the VR bound model as an inequality constraint in multimineral analysis for plausible alternative solutions. The SCA and DEM models provide good estimates in low-porosity intervals and imply geologic information for porous intervals. Then, we present a field case of the Bakken and Three Forks formations. A linear interpolation of the VR bound model helps validate multimineral results and approximate the elastic moduli of clay. There are two major advantages to using our new method: (1) Rock-physics effective medium models provide independent quality control of petrophysical multimineral results and (2) multimineral information leads to realistic rock-physics models.

Rock types, pore structures and permeability are essential petrophysical outputs, and they contribute considerably to the highest degree of uncertainty in reservoir characterisation. These factors have a strong influence on exploration and field development decisions. Core analysis is the best approach for estimating permeability, assigning rock types and characterising pore networks. Wireline logs are the most often employed method for estimating the parameters at each data point of reservoirs since there are more un-cored wells than cored wells. Artificial intelligence, on the other hand, is gaining popularity in the geosciences due to the ever-increasing complexity and volume of available subsurface data. This is also obvious in the demand for faster and more accurate interpretations in order to identify reservoir characteristics in increasingly difficult and complicated petroliferous basins. Artificial Neural Networks and Self-Organizing Maps are examples of machine learning approaches that can be used in both supervised and unsupervised modes for modelling and prediction. Eocene carbonates of Mukta oilfield are the major pay rocks of strong geological heterogeneity in terms of their porosity and permeability relationship with pore structures. This paper outlines a novel method of rock fabric classification, pore structure characterization, flow unit classification and robust reservoir permeability modelling based on an integrated approach that incorporates core measurements, log data and machine learning techniques. The pore structure has been characterised by the combination of conventional core, capillary pressure and nuclear magnetic resonance data. Artificial neural network has added an adequate benefit in accurate permeability modelling by utilizing the concepts of rock classifications and hydraulic flow units.

Tight sandstone reservoirs are characterized by low porosity, extra-low permeability, and diverse mineral compositions for which previously established log interpretation methods are not suitable. Therefore, it is necessary to explore new log interpretation methods. The committee machine is a recently developed composite expert network. The regression committee machine (RCM) is constructed by combining a backpropagation neural network (BPNN), extreme learning machine (ELM), wavelet neural network (WNN), and using two different weight calculators for decision-making. Petrophysical models for tight sandstone reservoirs are integrated together with the RCM. The RCM and petrophysical model hybrid intelligent system for log interpretation is developed. The data process flow and specific implementation method of the log interpretation are designed. The tenfold cross-validation method is used to train and optimize the parameters of the RCM in the hybrid intelligent system. The hybrid intelligent system is applied to the Chang 8 tight sandstone of Yanchang Formation in the Ordos Basin, China. The case studies show that the predicted porosity, permeability, and water saturation by the RCM with petrophysical models are all consistent with the core measurement. The data and models jointly driven intelligent system is more accurate than petrophysical models and individual expert networks. This study effectively improves the formation evaluation for tight sandstone reservoirs.

Digital, El objetivo de la presente práctica empresarial es realizar una búsqueda, recopilación e integración de registros e informes de pozo, imágenes UBI, caracterización de fracturas naturales, propiedades geomecánicas, sedimentología e información de producción del campo Cupiagua (4 Pozos) del piedemonte llanero. Mediante la recopilación de información a lo largo de bases de datos (Ecosearch, ICP, etc.) suministradas por la compañía, se logró mantener un estándar de calidad con los respectivos pozos evaluados en este proyecto siendo los pozos A y D los más completos y detallados para el respectivo estudio. Esto se realizó con el fin de completar la carga de información para los respectivos pozos y de visualizar la información relevante a escala 1D utilizando los softwares DSP (Decision space petrophysics) y Techlog, para así facilitar el entendimiento integrado de fracturas naturales en el campo. Como resultado se obtuvieron una serie de graficas para cada uno de los pozos del campo donde se integraron registros básicos, eventos, geomecánica, facies sedimentarias, diagramas de rosetas (fracturas), registros PLT (producción), imágenes UBI y CORE. Posteriormente con los datos ploteados se realizó el modelo petrofísico y una interpretación de fracturas en imagen UBI para el pozo D, el cual no contaba con la información., The objective of this company practice is to perform a search, compilation and integration of wells-logs and reports, UBI images, characterization of natural fractures, geomechanical properties, sedimentology, and production information of Cupiagua field (4 wells) in Llano’s foothills. Through the compilation of information along databases (Ecosearch, ICP, etc.) supplied by the company, it was possible to maintain a quality standard with the respective wells evaluated in this project, being wells A and D the most complete and detailed for the respective study. This was done in order to complete the information load for the respective wells and to visualize the relevant information at 1D scale using DSP (Decision space petrophysics) and Techlog software, to facilitate the integrated modeling of natural fractures in the field. As a result, a series of plots were obtained for each of the wells in the field where basic logs, events, geomechanics, sedimentary facies, rosette diagrams (fractures), PLT logs (production), UBI and CORE images were integrated. Subsequently, with the plotted data, the petrophysical model and an interpretation of fractures in UBI image for well D, which did not have the information, were made., Pregrado, Geólogo, Introducción Planteamiento del Problema Justificación del Problema Objetivos Objetivo General Objetivos Específicos Marco Teórico Yacimientos Naturalmente Fracturados ¿Qué es una Fractura Natural? Razones por las Cuales se Generan Fracturas Naturales Características de las Fracturas Clasificación Genérica Clasificación Geológica Morfología de las Fracturas Rasgos de las Fracturas Intensidad de Fracturamiento (Parámetros) Detección de Fracturas con Registros de Pozo Registros de Resistividad Registros Sónicos Registros de Densidad Variable (VDL) Registros de Imágenes de Pozo Registros de Imagen Ultrasónica Fracturas Naturales vs Inducidas Estado del Arte Bedoya, H. (2004). Caracterización de Fracturas Aplicadas a la Geomecánica de YNF. Piedemonte Llanero (Colombia) Ortiz, A. Cardozo, C. Reyes, A. (2005) Análisis Petrológico y de Microfracturamiento de las Formaciones Mirador y Barco, Pozo Cupiagua A-1 Ortiz, A. Ramírez, A. (2007) Cálculo de Porosidad Secundaria o de Fractura a Partir de Registros Convencionales y Permeabilidad de Fractura a Partir de Pruebas de Presión Para la Formación Mirador del Piedemonte Llanero Ortiz, A. Cantillo, J. (2006) Impacto Geomecánico y Yacimientos Naturalmente Fracturados Beltrán, X. (2005). Estudio Sobre la Relación Existente Entre la Sedimentología y el Fracturamiento en el Campo Cupiagua a Partir de Análisis de Corazones Grupo de Modelamiento de Procesos Hidrocarburos (2004) Determinación de la Intensidad de Fracturamiento y su Incidencia Sobre la Permeabilidad de los Yacimientos Naturalmente Fracturados Ortiz, A. Naranjo, J. Torres, E. (2007) Análisis Petrológico y de Microfracturamiento (Formaciones Mirador y Barco) Campos Floreña, Pauto y Volcanera Localización y Generalidades Ubicación Espacial Columna Estratigráfica General Metodología Modelo de Porosidad Resultados Revisión de Estado de los Pozos Curvas Modeladas (Gráficos) Pozo A Pozo B Pozo C Pozo D Modelo Petrofísico (Pozo D) Gráfico de Petrofísica Cutoff Sensitivity PHI (Formación A y B) Cutoff Sensitivity Vcl (Formación A y B) Comparación GR- Formación A y B Resultados PHI- Formación B Resultados PHI- Formación A Resultados Generales de la Petrofísica Interpretación de Fracturas (Pozo D) Resultados de la Interpretación e Input Generado Para el Modelamiento Discreto de Fracturas (MDF) Conclusiones Referencias Bibliográficas

As part of Geoscience Australia’s Exploring for the Future program, this study aims to analyse the hydrocarbon prospectivity in the Carrra Sub-basin through wireline log interpretation and shale gas reservoir characterisation. NDI Carrara 1 is the first stratigraphic test of the Carrara Sub-basin, a recently uncovered depocentre located within the South Nicholson region of the eastern Northern Territory and northwestern Queensland. Four chemostratigraphic packages were defined according to the informal sub-division of stratigraphy and inorganic geochemical properties. Wireline log interpretation has been conducted to derive the clay mineral compositions, porosity, gas saturation and gas contents for the unconventional shale gas reservoirs in the Proterozoic succession in NDI Carrara 1. The predominant clay minerals include illite/muscovite, mixed-layer clay, smectite, kaolinite, and minor contents of glauconite and chlorite. The average geothermal gradient is estimated to be 35.04 °C/km with a surface temperature of 29.4 °C. The average formation pressure gradient is calculated to be < 10.7 MPa/km from mud weight records. Artificial neural network technology is used to interpret the TOC content from wireline logs for unconventional shale gas reservoirs. TOC content is positively correlated with methane and ethane concentrations in mudlog gas profiles, shale porosity, formation resistivity and gas content for NDI Carrara 1. The organic-rich shales in P2 have favourable adsorbed, free and total gas contents. The organic-rich micrites within P3 have the potential in adsorbed gas, but with very low average gas saturation (< 0.01 m3/m3). Our interpretation has identified potential shale gas reservoirs, as well as tight non-organic-rich shales and siltstones with potential as gas reservoirs. These occur throughout several of the identified chemostratigraphic packages within the Proterozoic section of NDI Carrara 1.

В статье описан новый подход к численной оценке абсолютной проницаемости керна горных пород по их микротомографическим изображениям, позволяющий выполнять эту оценку на персональных компьютерах с использованием ограниченных вычислительных ресурсов. Подход обусловлен тем, что современные микротомографические изображения зачастую имеют размеры 1000 вокселей и выше при разрешении 1–3 мкм на воксель. В работе показано, что даже относительно небольшие подобласти изображений могут использоваться для оценки проницаемости с последующим построением устойчивых корреляционных зависимостей между открытой пористостью и абсолютной проницаемостью. В результате построенные зависимости могут быть как обобщены на весь образец при известной связной пористости (оцененной численно или лабораторно), так и экстраполированы на масштаб полноразмерного керна., The paper describes a new approach to the numerical estimation of the absolute permeability of rocks using their CT-scans. The algorithm is designed to be used on a limited computational resources, such as single GPU or a desktop. Modern microtomographic images often have sizes of 1000 voxels and a resolution of 1–3 µm per voxel. In this case, relatively small sub-regions can be used to estimate permeability, followed by the construction of stable correlations between open porosity and absolute permeability. As a result, the constructed dependences can be either generalized to the entire sample with a known connected porosity (estimated numerically or laboratory), or extrapolated to the scale of a full-sized core., ГЕОФИЗИКА, Выпуск 1 2023, Pages 34-40

Im Rahmen von unweltbezogenen bzw. ingenieurtechnischen Untersuchungen werden die Eigenschaften des Untergrunds traditionell mit direkten Messmethoden erfasst. Jedoch sind die gewonnenen Daten in ihrer räumlichen Auflösung begrenzt, da direkte Untersuchungen meist nur punktuell durchgeführt werden können (z.B. in Bohrlöchern). Im Gegensatz dazu sind geophysikalische Methoden in der Lage, Informationen über die Beschaffenheit des Untergrunds in nicht-invasiver Weise und mit hoher räumlicher und zeitlicher Auflösung zu bestimmen, und haben sich daher als geeignete Ergänzung von direkten Methoden erwiesen. Die elektrische Widerstandstomographie (electrical resistivity tomography; ERT) und die seismische Refraktionstomographie (seismic refraction tomography; SRT) sind in der Lage Veränderungen der hydrogeologischen bzw. chemischen Eigenschaften des Untergrunds zu detektieren und werden daher häufig für oberflächennahe Untersuchungen eingesetzt. Die Kombination diese komplementären geophysikalischen Methoden ist ein gängiger Ansatz, um den Einfluss von Unsicherheiten bzw. Fehler im Zusammenhang mit der Datenerfassung, -verarbeitung und -inversion auf die Ergebnisse zu vermindern. Das sorgfältige Prozessieren der geophysikalischen Daten ist von zentraler Bedeutung, um verlässliche Modelle der Untergrundeigenschaften zu erhalten. Insbesondere die Prozessierung von ERT-Datensätzen kann basierend auf etablierten Richtlinien und Algorithmen weitestgehend automatisiert werden. Im Gegensatz dazu handelt es sich bei der Prozessierung von SRT-Daten um einen interaktiven Vorgang, der maßgeblich von der Erfahrung der auswertenden Person beeinflusst wird und zudem oftmals den Einsatz von kommerziellen Softwarelösungen erfordert. Dementsprechend besteht begründeter Bedarf an der Entwicklung von lizenzfreien bzw open-source Lösungen, die transparente und automatisierte Abläufe im Zusammenhang mit der Prozessierung von SRT-Daten ermöglichen. Bei der Inversion von geophysikalischen Daten handelt es sich um ein mehrdeutiges Problem, wodurch insbesondere die Interpretation der Inversionsergebnisse mit Unsicherheiten behaftet sein kann, die zusätzlich verstärkt werden, wenn die geophysikalischen Parameter in andere Größen umgerechnet werden (z.B. die von direkten Methoden erfassten Untergrundeigenschaften). In dieser Hinsicht ist eine verbesserte Interpretation durch die Kombination komplementärer Inversionsergebnisse möglich, jedoch setzt dies voraus, dass die durch unabhängige Inversionen erhaltenen Untergrundmodelle in sich konsistent sind.Um diese Nachteile zu beheben, hat sich die petrophysikalisch gekopplete Inversion (petrophysical joint inversion; PJI) von ERT- und SRT-Daten als ein geeignetes Verfahren erwiesen, welches die direkte quantitative Bestimmung der relevanten Untergrundeigenschaften (z.B. hydrogeologische Parameter) ermöglicht. Jedoch erfordert die Anwendung solcher PJI-Verfahren eine adäquate Parametrisierung des zugrundeliegenden petrophysikalischen Modells, die wiederum von Unsicherheiten betroffen sein kann. Daher untersucht diese Arbeit die Möglichkeit, strukturelle und petrophysikalische Randbedingungen in der petrophysikalisch gekoppelte Inversion zu berücksichtigen, um konsistente Untergrundmodelle zu erhalten.Bei einem hohen Anteil von tonigen Sedimenten oder organischem Material ist es essentiell, dass das dem PJI-Verfahren zugrundeliegende petrophysikalische Modell den Einfluss der Oberflächenleitfähigkeit auf die beobachteten elektrischen Eigenschaften des Untergrunds berücksichtigt. Wird dieser Einfluss bei der PJI vernächlässigt, führt dies zu einer fehlerhaften quantitativen Bestimmung der hydrogeologischen Untergrundeigenschaften. Dementsprechend wird in dieser Arbeit das eingesetzte PJI-Verfahren erweitert, um den Einfluss der Oberflächenleitfähigkeit im Zuge der Inversion, d.h., bei der Parameterschätzung, zu berücksichtigen. Dieses modifizierte PJI-Verfahren quantifiziert die Oberflächenleitfähigkeit basierend auf ERT-Daten, die bei einer niedrigen und einer hohen Frequenz gemessen werden.Die im Rahmen dieser Arbeit erzielten Resultate lassen sich wie folgt zusammenfassen: (i) Entwicklung einer Softwarelösung für die Modellierung und Prozessierung von SRT-Daten basierend auf open-source python-Bibliotheken; (ii) die Verwendung eines Porositätsmodells als Randbedingung in der PJI kompensiert einen etwaigen geringen Kontrast in den physikalischen Eigenschaften verschiedener Untergrundmaterialien und kann darüber hinaus als zeitliche Randbedingung fungieren; (iii) der frequenzabhängige Effekt der Oberflächenleitfähigkeit kann im Zuge der PJI basierend auf Leitfähigkeitsmessungen bei einer hohen und einer niedrigen Frequenz berücksichtigt werden; (iv) das erweitertete PJI-Verfahren ermöglicht die quantitative Bestimmung hydrogeologischer Parameter (insbesondere Wassergehalt und hyrdaulische Leitfähigkeit) in unterschiedlichen Untersuchungsgebieten, z.B. gefrorener Untergrund in alpinen Regionen, Deponien, Hangrutschungen und ungestörte natürliche Sedimente; (v) das verwendete PJI-Verfahren kann sowohl hinsichtlich der zu invertierenden Datensätze als auch der Zielparameter individuell angepasst werden, wodurch zukünftige Erweiterungen basierend auf weiteren geophysikalischen Methoden und petrophysikalischen Beziehungen möglich sind., Geophysical methods have proven to be suitable for complementing traditional pointwise direct investigations in environmental and engineering studies, as they provide information regarding the subsurface properties with high spatio-temporal resolution in a non-invasive manner. In near-surface investigations, electrical resistivity tomography (ERT) and seismic refraction tomography (SRT) methods are commonly applied due to their sensitivity to variations in the hydrogeological or chemical properties of the subsurface materials. In particular, the joint application of these geophysical techniques with complementary sensitivities is a common approach to mitigate the effect of uncertainties associated with data collection, processing and inversion on the consistency in the obtained results.A careful processing of the geophysical data is critical for the estimation of reliable subsurface models. In case of the ERT, the data processing can be automatized to a high degree due to the availability of well-established guidelines and algorithms. In contrast, the SRT data processing refers to an interactive procedure controlled by user experience commonly relying on commercial software solutions. Accordingly, the geophysical modeling and processing library proposed in this thesis addresses the justified demand for open-source tools facilitating transparent and more automatized SRT processing workflows.Due to the non-uniqueness of the geophysical inversion problem the interpretation of the resolved subsurface models is also associated to uncertainties, which might be further amplified if the geophysical images are transformed to quantitative estimates of the actual parameters of interest. The combination of complementary imaging results aims at a more reliable interpretation, yet inconsistencies in the models obtained from independently inverted data sets might limit the applicability of such approach. To overcome these limitations of joint interpretation approaches, petrophysically coupled joint inversion (PJI) schemes based on ERT and SRT data have emerged as innovative tools due to their ability to directly solve for subsurface models expressed in terms of the actual target parameters, e.g., hydrogeological properties. However, the parameterization of the underlying petrophysical model might also be affected by uncertainties. Hence, this thesis explores the possibility to impose structural and petrophysical constraints on the PJI to enhance the consistency in the resolved subsurface models.In fine-grained environments or in presence of organic matter, neglecting the effect of the surface conduction on the observed electrical response results in biased estimates for the hydrogeological target parameters. Accordingly, this study extends the PJI scheme to consider surface conductivity during the parameter estimation by leveraging upon the frequency-dependence of the surface conductivity obtained through ERT data collected at a low and a high frequency.In summary, the results presented in this thesis demonstrate: (i) the ability to build modeling and processing tools for seismic refraction data based on open-source python libraries; (ii) that imposing a porosity model as constraint in the PJI compensates for the lack of contrast in the physical properties of different media and can also act as a time-lapse constraint in the PJI; (iii) that the frequency-dependent effect of the surface conduction can be taken into account during the PJI parameter estimation based on conductivity magnitude data collected at a high and a low frequency; (iv) the applicability of the PJI to solve for hydrogeological parameters, e.g., water content and hydraulic conductivity, in different environments ranging from frozen conditions in alpine regions, to landfills, landslides and undisturbed natural media; and (v) the possibility to adapt the PJI framework with regard to both input data and target parameters, which lays the foundation for future incorporation of other geophysical methods and petrophysical relationships.

High economic and metallogenic significance of northern Norrbotten ore district in Sweden which hosts Kiruna mining district makes it a very important ore district in the world. Northern Norrbotten ore district contributes a combined 90 percent of iron production in Europe. Present day Kiruna mining district is host to Iron-oxide-Apatite (IOA), Viscaria, Iron-Oxide-Copper-Gold and Pahtohavare deposits. However, it is famous for its IOA Kirunavaara mineralization which is a giant ore body of high-grade magnetite. Results from earlier mineral prospecting activities indicates volume of orebody diminishes at depth especially towards the south. In this study, petrophysical measurements and data analysis of rock samples from outcrops in Kiruna mining district are performed. Physical rock properties govern geophysical survey techniques hence are used as petrophysical constraint in geophysical modelling to develop a common earth model of the mining district. Common earth modelling involves integrating all relevant geological, geophysical and petrophysical data in the model. This is to improve the understanding and knowledge of the orebody and aid long term mine planning activities in the mining district. Rock physical properties investigated include density, magnetic (anisotropy of magnetic susceptibility, natural remanent magnetisation) and electrical (complex electrical resistivity) properties. Block samples were collected from 34 outcrops in the Kiruna mining district and cut into cubes. Density of rocks samples ranged from 2388 to 3093 kgm-3. Rock types of most samples are belonging to the porphyry group based on previous gravity and density modelling of Kirunavaara mineralization. Variation in degree of induced (anisotropic) magnetic susceptibility (AMS), dominance of prolate ellipsoid of AMS parameters follow trend of geological structures are noted with reference to rock types. Mechanism of induced polarization (IP) in rock samples is of grain polarization type due to presence of metallic minerals disseminated in the rock samples. Complex electrical resistivity in wet rock samples increases with increasing frequency. Magnetisation in outcrops 01 and 21 is largely influenced by remanent magnetisation whereas magnetisation of outcrops 03 and 02 is influenced by induced magnetisation. Nature of magnetisation is determined based on computed magnitude of Königsberger ratio calculated from two types of measuring setups, here referred as gradiometer and oersted-meter approaches. Thus, the natural remanent magnetisation (NRM) in rocks is estimated in addition to induced magnetisation.

A review of the petrophysical properties involving formation damage is presented. Variation of the end-point saturations with porosity and permeability, fluid disposition, distribution, and entrapment, flow functions, and petrophysical parameters of geologic formations, dependence of the flow functions, such as capillary pressure and relative permeability, on the end-point saturations, wettability, and clay morphology, and temperature and stress effects are discussed. The interrelations between the various factors affecting formation damage are described.

Funding: This study was supported by the Interreg NWE Programme through the Roll-out of Deep Geothermal Energy in NorthWest Europe (DGE-ROLLOUT) Project (www.nweurope. eu/DGE-Rollout). The Interreg NWE Programme is part of the European Cohesion Policy and is financed by the European Regional Development Fund (ERDF). Further funding was provided by the Bundesministerium für Wirtschaft und Energie of NRW and the Ruhr-University Bochum Research Department under the Closed Carbon Cycle Economy project. A multi-proxy field and laboratory study was conducted to investigate the impact of a regional fault zone on Devonian carbonate geothermal reservoir properties. The outcrop analogue chosen is exposed in the Steltenberg quarry (North Rhine-Westphalia, Germany) and provides access to Devonian lime- and dolostone units affected by branches of the Ennepe Thrust Fault zone. Data presented include (i) field evidence from sedimentological and structural data, (ii) petrographic and mineralogical analyses, and (iii) geochemical and petrophysical data. Although the interpretation of the depositional environment is not trivial, the carbonate facies present generally reflect the shedding of reefal material from large bioherms to the west of the study areas as well as localised, small bioherms prone to storm disintegration. The inherited properties of these carbonates at deposition, and a clear understanding of their diagenetic history, are the prerequisite for extrapolation between outcrop analogues and their corresponding subsurface units. We document a detailed interpretation of the paragenetic sequence that affected these rocks from deposition, burial, subsequent hydrothermal overprint related to rock disintegration and fluid circulation along the fault zone, and finally, late-stage meteoric overprint. Emphasis is placed on various forms of dolomitisation and its effect on rock properties and reservoir quality. The resulting scenario is complex, and when comparing the data from the Steltenberg quarry with nearby outcrops, significant regional heterogeneity is observed. It is important to separate between: (i) diffuse, locally distributed dolomitisation, (ii) replacive dolomitisation (fronts), spatially separating lime- and dolostones, and (iii) fault-bound, hydrothermal dolomitisation. The Devonian carbonates in the Steltenberg quarry examined here have higher thermal conductivity compared to the Jurassic (Malm) carbonate units in the Munich area, with some even higher than the values of massive limestone facies of the Munich area. As a large portion of North Rhine-Westphalia’s territory is underlain by Devonian carbonates, this is considered significant. However, emphasis is placed on the fact, that data shown here document the spatially complex organisation of rock types and their reservoir properties. This presents a warning against oversimplifications when extrapolating observations from outcrops into subsurface rock bodies. Publisher PDF

Traditional petrophysical methods to evaluate organic richness and mineralogy using gamma-ray and resistivity log responses are not diagnostic in source rocks. We have developed a deterministic, nonproprietary method to quantify formation variability in total organic carbon (TOC) and three key mudrock mineralogical components of nonhydrocarbon-bearing source rock strata of the Eagle Ford Group by developing a set of log-derived multimineral models calibrated with Fourier transform infrared spectroscopy core data from the research borehole U.S. Geological Survey Gulf Coast 1 West Woodway. We determined that bulk density response is a reliable indicator of organic content in these thermally immature, water-bearing source rocks. Multimineral findings indicate that a high degree of laminae-scale mineralogical heterogeneity exists due to thinly interbedded carbonate cements amid clay-rich mudstone layers. The lower part of the Eagle Ford Group contains the highest average TOC content (4.7 wt%) and the highest average carbonate volume (64.1 vol%), making it the optimal target in thermally mature areas for source-rock potential and hydraulic-fracture placement. In contrast, the uppermost portion of the Eagle Ford Group contains the highest average volume of clay minerals (42.6 vol%), which increases the potential for wellbore stability issues. Petrophysical characterization reveals that porosity is approximately 30% in this relatively uncompacted formation. In this thermally immature source rock, water saturation is nearly 100% and no free hydrocarbons were observed on the resistivity logs. No evidence of borehole ellipticity was observed on the three-arm caliper log, and horizontal stresses are presumed to be directionally uniform in the vicinity of this near-surface wellbore. This shallow wellbore has a temperature gradient of 1.87°F/100 ft (16.3°C/km) and is likely influenced by earth surface heating.

An embedded model estimator (EMBER) petrophysical modeling algorithm has been applied to obtain effective porosity and permeability within the presalt carbonate reservoirs of the Barra Velha Formation in Buzios Field, Santos Basin. This advanced methodology was used due to the heterogeneity and complexity of the reservoirs, which makes modeling by conventional geostatistical methodologies difficult. For effective porosity modeling, we chose one facies model, one stratigraphic seismic attribute (acoustic impedance), and one structural seismic attribute (local flatness) as secondary variables. Permeability was modeled by using the best effective porosity simulation result as a secondary variable. Our results demonstrate that average effective porosity and permeability were 0.10 v/v and 440 md, respectively, indicating good reservoir quality throughout the studied area. A vertical trend of high effective porosities and permeabilities for the basal and uppermost reservoir sections was identified in our results, as well as a trend with lower values for these reservoir properties for the intermediate reservoir section. The lower section of the formation presented more continuity, and we infer it to be the best reservoir interval. We observed two horizontal trends for these reservoir properties at the formation top: one of higher values aligned to the north–south direction at the structural highs and another of lower reservoir properties related to isolated structural lows within structural highs. Correlation between modeled results and the blind test ANP-1 well upscaled properties was high, and upscaled well-log property distributions were preserved in the EMBER simulations, proving the predictive capacity of the algorithm. Finally, conditional distributions analysis indicated that the basal section of the Barra Velha Formation presents higher uncertainty for the estimation of effective porosity. Even though this interval is considered to have the best reservoir characteristics, decision making should be done with caution for this section.

Rock physics provides a dynamic tool for quantitative analysis by developing the basic relationship between fluid, lithological, and depositional environment of the reservoir. The elastic attributes such as impedance, density, velocity, V p/V s ratio, Mu-rho, and Lambda-rho are crucial parameters to characterize reservoir and non-reservoir facies. Rock physics modelling assists like a bridge to link the elastic properties to petrophysical properties such as porosity, facies distribution, fluid saturation, and clay/shale volume. A robust petro-elastic relationship obtained from rock physics models leads to more precise discrimination of pay and non-pay facies in the sand intervals of the study area. The Paleocene aged Lower Ranikot Formation and Pab sandstone of Cretaceous age are proven reservoirs of the Mehar gas field, Lower Indus Basin. These sands are widely distributed in the southwestern part of the basin and are enormously heterogeneous, which makes it difficult to distinguish facies and fluid content in the reservoir intervals. So, an attempt is made in this paper to separate the reservoir facies from non-reservoir facies by using an integrated approach of the petro-elastic domain in the targeted sand intervals. Furthermore, missing logs (S-sonic and P-sonic) were also synthesized in the wells and missing intervals along with improving the poor quality of the density log by captivating the washouts and other side effects. The calibrated rock physics model shows good consistency between measured and modelled logs. Petro-elastic models were predicted initially using petrophysical properties and incorporated at true reservoir conditions/parameters. Lithofacies were defined based on petrophysical cut-offs. Rock physics modelled elastic properties (Lambda-rho versus Mu-rho, impedance versus V p/V s ratio) were then cross-plotted by keeping lithofacies in the Z-axis. The cross-plots clearly separated and demarcated the litho-fluid classes (wet sand, gas sand, shale, and limestone) with specific orientation/patterns which were randomized in conventional petrophysical analysis.

Achieving a thorough understanding of how primary sedimentary granularity drives considerable heterogeneity in internal reservoir attributes of terrigenous fine-grained deposits is of great significance. We investigated the quantitative differentiation and its corresponding driving forces of physical reservoir properties and pore-structure characteristics of silty-mud sediments in the Upper Triassic Xujiahe Formation (SW China) using a multi-method approach. The results show that the micro-mesopore volume and surface area of mudstones/shales are apparently higher than those of silty mudstones and a remarkable threefold rise in average permeability also presents. Extensively distributed bitumen pores occurring mostly along brittle mineral grains or forming clay-organic complexes make considerable contributions to shrinking microcracks. Furthermore, an evidently higher concentration of clay minerals in mudstone/shale reservoirs is primarily responsible for development of the two types of clay inter-crystalline pores distributed along grain aggregates and between well-oriented platelets. These two major causes facilitate the formation of micro-bedding fractures/non-bedding microfractures and connected fracture and pore-fracture networks, and also high-quality argillaceous reservoirs by strongly enhancing storage spaces and seepage capacities. Finally, a conceptual model is established for interpreting a differential reservoir-forming mechanism and corresponding two-sided effects on petrophysical and reservoir quality properties for continental silty-mud sediments.

Brownfield areas are important targets of exploration; however, the extensive drilling present in these areas has not fully exploited their prospective potential. The appropriate use of drill hole cores in these areas can play an important role in deep exploration. We present a case study of iron oxide-copper-gold (IOCG) Furnas Southeast deposit, located in the Carajás Mineral Province, Brazil. This deposit has disseminated chalcopyrite, bornite and gold mineralization associated with a silicic (Si), potassic (K), calcic (Na), sodic-calcic (Na-Ca) hydrothermal alteration, and intense iron metasomatism with massive magnetite (Fe) alteration. Petrophysical hand-held equipment measurements were carried out on drill core samples with the purpose of studying the potential roles that magnetic susceptibility properties can play in high-grade mineralization. The results indicate that the geological complexity of the IOCG deposit is readily reflected in the extensive variation of the measurements. The statistical analysis shows how the detailed characterization of this physical property carried out for this mineral association could effectively define and describe ore, and the magnetic susceptibility footprints of hydrothermal alteration zones. Furthermore, we were able to perform a magnetic susceptibility 3D modeling of diamagnetic, paramagnetic, and ferrimagnetic responses strictly correlated with known orebody. Thus, petrophysical analyses can form a quantitative geological criterion for ore delineation.

The present study investigates the reservoir characteristics of the Mount Messenger Formation of Kaimiro-Ngatoro Field which was deposited in deep-water environment. A 3D seismic dataset, core data and well data from the Kaimiro-Ngatoro Field were utilized to identify lithofacies, sedimentary structures, stratigraphic units, depositional environments and to construct 3D geological models. Five different lithologies of sandstone, sandy siltstone, siltstone, claystone and mudstone are identified from core photographs, and also Bouma sequence divisions are also observed. Based on log character Mount Messenger Formation is divided into two stratigraphic units slope fans and basin floor fans; core analysis suggests that basin floor fans show better reservoir qualities compared to slope fan deposits. Seismic interpretation indicates 2 horizons and 11 faults, majority of faults have throw less than 10 m, and most of the faults have high angle dips of 70–80°. The Kaimiro and Ngatoro Fields are separated by a major Inglewood fault. Variance attribute helped to interpret faults, and other seismic attributes such as root-mean-square amplitude, envelope and generalized spectral decomposition also helped to detect hydrocarbons. The lithofacies model was constructed by using sequential simulation indicator algorithm, and the petrophysical models were constructed using sequential Gaussian simulation algorithm. The petrophysical parameters determined from the models comprised of up to ≥ 25% porosity, permeability up to around 600mD, hydrocarbon saturation up to 60%, net to gross varies from 0 to 100%, majority of shale volumes are around 15–20%, the study interval mostly consists of macropores with some megapores and 4 hydraulic flow units. This study best characterizes the deep-water turbidite reservoir in New Zealand.

The estimation of petrophysical and fluid-filling properties of subsurface reservoirs from seismic data is a crucial component of reservoir characterization. Seismic amplitude-variation-with-offset (AVO) inversion driven by rock physics is an effective approach to characterize reservoir properties. In general, PP-wave reflection coefficients, elastic moduli, and petrophysical parameters are nonlinearly coupled, especially in multiple-type pore-space reservoirs, which makes seismic AVO petrophysics inversion ill-posed. We have developed a new approach that combines Biot-Gassmann’s poroelasticity theory with Russell’s linear AVO approximation, to estimate the reservoir properties including elastic moduli and petrophysical parameters based on multitrace probabilistic AVO inversion algorithm. We first derive a novel PP-wave reflection coefficient formulation in terms of porosity, stiff-pore volume fraction, rock-matrix shear modulus, and fluid bulk modulus to incorporate the effect of pore structures on elastic moduli by considering the soft and stiff pores with different aspect ratios in sandstone reservoirs. Through the analysis of the four types of PP-wave reflection coefficients, the approximation accuracy and inversion feasibility of the derived formulation are verified. Our stochastic inversion method aims to predict the posterior probability density function in a Bayesian setting according to a prior Laplace distribution with vertical correlation and prior Gaussian distribution with lateral correlation of model parameters. A Metropolis-Hastings stochastic sampling algorithm with multiple Markov chains is developed to simulate the posterior models of porosity, stiff-pore volume fraction, rock-matrix shear modulus, and fluid bulk modulus from seismic AVO gathers. The applicability and validity of our inversion method is illustrated with synthetic examples and a real data application.

The present study is aimed to recognize the structural styles of hydrocarbon exploration and petrophysical properties of the LGF. The 2-D seismic and well log data set is composed of three seismic lines and well log data of Chak 66–1. Five horizons have been marked with the help of well to seismic tie namely tops of Ranikot, Parh, upper Goru, lower Goru, basal and top massive sands, and out of which basal and massive sands are the objective focus of the present study. Based on seismic data, the study area is characterized by normal faults showing NW–SE dipping trend. Horst and graben structural features are prominent on the seismic lines, which indicated the extensional tectonic regime. Time–depth contour maps and 3D surfaces of objective horizons depict their actual spatial distribution in this area. Wireline logging analysis revealed the physical properties of both basal and massive grains of sand, as 17% effective porosity, 25% average volume of shale (Vsh), 40% water and 60% hydrocarbon saturations for basal sands, Whereas, 16% effective porosity, 35% Vsh, 30% water and 70% hydrocarbon saturations are interpreted for massive sands. Cross–plots of Nphi–Dt and Dt–Rhob also identified that both areas of sand are clean, gas–saturated and have the potential to produce hydrocarbons.

Stochastic petrophysical inversion is a method used to predict reservoir properties from seismic data. Recent advances in stochastic optimization allow generating multiple realizations of rock and fluid properties conditioned on seismic data. To match the measured data and represent the uncertainty of the model variables, many realizations are generally required. Stochastic sampling and optimization of spatially correlated models are computationally demanding. Monte Carlo methods allow quantifying the uncertainty of the model variables but are impractical for high-dimensional models with spatially correlated variables. We have developed a Bayesian approach based on an efficient implementation of the Markov chain Monte Carlo (MCMC) method for the inversion of seismic data for the prediction of reservoir properties. Our Bayesian approach includes an explicit vertical correlation model in the proposal distribution. It is applied trace by trace, and the lateral continuity model is imposed by using the previously simulated values at the adjacent traces as conditioning data for simulating the initial model at the current trace. The methodology is first presented for a 1D problem to test the vertical correlation, and it is extended to 2D problems by including the lateral correlation and comparing two novel implementations based on sequential sampling. Our method is applied to synthetic data to estimate the posterior distribution of the petrophysical properties conditioned on the measured seismic data. The results are compared with an MCMC implementation without lateral correlation and demonstrate the advantage of integrating a spatial correlation model.

In unconventional reservoirs, the pore space is hosted by a heterogeneous matrix with various minerals and organic components. This heterogeneity complicates petrophysical interpretation during hydrocarbon exploration. A digital rock physics study of thermal and electrical conductivity was conducted using high-resolution focused ion beam scanning electron microscopy images of carbonate-rich source rocks. Finite-volume simulation results are discussed in context of the sample heterogeneity and anisotropy and supported by comparisons to empirical equations and effective medium theory. The results show how the presence of organic matter, pyrite, and pore constrictions impacts application of empirical equations and simplified models to unconventional reservoirs.Graphic abstract

We have characterized the petrophysical and geomechanical properties of the Late Cretaceous Turonian and Cenomanian carbonate reservoirs from the southeast Constantine Basin, northern Algeria. In general, Turonian carbonates exhibit a wide range of porosities (2%–15%) and permeabilities (0.001–10 mD), whereas the Cenomanian reservoir appears to be very tight (10% porosity and 0.5–10 mD permeability). The reservoir pore-pressure gradient is interpreted to be a little above the hydrostatic (0.51 psi/ft), whereas the minimum horizontal stress ([Formula: see text]) has a 0.72 psi/ft gradient. In situ stress analysis establishes a dominant strike-slip tectonic stress field in the basin. Shale intercalations associated with the carbonate facies are characterized by comparatively high failure pressure that can lead to wellbore failures, which may be avoided considering the recommended minimum drilling mud weight as obtained from the rock failure criterion. Extensive wellbore breakouts (C-quality) were observed in the acoustic image logs recorded in the studied reservoir intervals, inferring a mean maximum horizontal stress azimuth of 350°N. We recommend that deviated wells in the direction of the interpreted [Formula: see text] orientation (approximately east–west) using hydraulic fracturing can be useful to attain optimum wellbore stability and effective permeability enhancement. Our findings have significant implications for enhanced production within the tight carbonate reservoirs situated in a strike-slip domain.

A standard digital rock physics workflow aims to simulate petrophysical properties of rock samples using few millimeter size subsets scanned with X-ray microtomography at a high resolution of around 1 μm. The workflow is mainly based on image analysis and simulation procedures at a subset scale leading to potential uncertainties and errors that cannot be quantified experimentally. To overcome the gap between scales, we propose to integrate three-dimensional (3D) printing technology to generate enlarged subsets at a scale where experimental measurements are feasible to validate simulated results. In this study, we 3D printed synthetic and real samples and compared digital and experimental rock properties. The most challenging phase in the workflow consists of the difficulties encountered while cleaning the 3D printed samples to remove the support material. Results for subsets extracted from synthetic, sandstone, and carbonate samples showed good agreement between digital and experimental measurements for porosity values less than 12% and a range of permeability values between 100 and 2000 mD.

Cores, thin sections, and cathodoluminescence (CL) analysis were integrated to document the occurrence and petrology of dolomites, and their pore systems in the Cambrian of Tarim Basin, China. Depositional facies, pore types and dolomitization processes of various dolostone reservoir types are determined. Six types of dolomite are recognized, including microbial dolomite, dolomicrite, fabric retentive dolomite, fabric-obliterative dolomite, fine to medium crystalline dolomite cement, and saddle dolomite cement. Pore systems are dominantly vugs, anhydrite dissolution pores, intercrystalline pores, intercrystalline dissolution pores, fabric dissolution pores and microfractures. Four porous dolostone reservoirs include sabkha dolostone, seepage-reflux dolostone, burial dolostone, hydrothermal dolostone. Fractures play an important role in enhancing reservoir quality in dolostone reservoirs. Conventional wireline logs and image logs are calibrated with cores and related thin sections. Sabkha dolostone reservoirs are characterized by dark and bright spots on the image logs. Seepage-reflux dolostone reservoirs are related to high-energy depositional facies and are characterized by low gamma-ray amplitude, increasing sonic transit time and neutron porosity but reducing bulk density values. Evident dark spots (vugs) are recognized on image logs, and all three porosity logs suggest relatively high reservoir quality in burial dolostone reservoirs. Hydrothermal dolostone reservoirs are recognized by high gamma-ray response caused by hydrothermal minerals (fluorite), and porosity curves indicate good reservoir quality, which is supported by dark spots (vugs) on the image logs. Rapid decrease in resistivity, increasing in sonic transit time values, and the dark sinusoidal waves on the image logs are typical of fractured dolostone reservoirs. The distribution of dolostone reservoirs in each well is predicted using a comprehensive analysis of conventional and image logs, and they are calibrated with oil test data. The research provides insights in the analysis of genetic model of deeply buried dolostone reservoirs and establishes the predictable model for reservoir quality in dolostones via well logs.

In this paper we present the application of a single-loop litho-petro-elastic (LPE) inversion, which is a data assimilation algorithm that uses nonlinear Zoeppritz reflectivity operators with sequential filtering. It integrates rock physics models with seismic amplitude variation with offset (AVO) inversion and Bayesian inversion to define lithology, elastic, and petrophysical properties in a single loop, thus, combining several steps of the conventional reservoir characterization workflow. In the conventional multistep approach, the lithology and petrophysical properties are generated sequentially from elastic properties after AVO inversion is performed, which can add prediction uncertainty at each step and produce results that are not correlated with each other. The LPE inversion ensures that the predicted properties maintain the relationships defined by the rock physics model. The LPE inversion was tested on data from offshore Australia with three wells, for a faulted reservoir zone containing oil with a gas cap. It provided robust predictions for lithology, porosity, and water saturation, which matched acceptably at the three wells. The algorithm also accounted for subsurface uncertainties as it produced prediction probabilities of facies, porosity, and water saturation using multidimensional probability density functions. This approach can be effectively used to classify reservoir properties in a single-loop workflow.

The previous studies on the petrophysical and volumetric analysis of Habiganj gas field were based on limited well data. As the accuracy of volumetric analysis relies greatly on petrophysical parameters, it is important to estimate them accurately. In this study we analyzed all eleven wells drilled in the Habiganj field to determine the petrophysical parameters. Analysis of the well logs revealed two distinct reservoir zones in this field termed as upper reservoir zone and lower reservoir zone. Stratigraphically, these two reservoir zones are in the Bokabil and Bhuban Formation of Surma Group. Petrophysical analysis shows significant differences between the two zones in terms of petrophysical parameters. Porosity in the upper reservoir zone ranges from 12% to 36%, with an average of 28%. This zone is highly permeable, as indicated by the average permeability of 500 mili Darcy (mD). The average water saturation in this zone is around 18% suggesting high gas saturation. The lower reservoir zone has an average porosity, permeability, and water saturation of 12%, 60mD, and 43%, respectively, indicating poor reservoir quality. An analysis of log motifs indicates that the upper reservoir zone is composed of stacked sands of blocky pattern. The sands in this interval are clean, as indicated by the lower shale volume of 12-15%. The average thickness of this zone is 230m, and the presence of this zone in all the drilled wells suggests high lateral continuity. The lower reservoir zone consists of sand bodies of serrated pattern. The sands have high shale volume and are laterally discontinuous. Overall, the upper reservoir zone has superior petrophysical properties to the lower reservoir zone. Although the reservoir quality of the lower reservoir zone is poorer than that of the upper zone, this zone can be considered as the secondary target for hydrocarbon production. Petrophysical parameters of this study were estimated from all the eleven wells drilled in this field; hence the values are more accurate. The reported values of the petrophysical parameters in this study are recommended to use to re-estimate the reserves in Habiganj field. The Dhaka University Journal of Earth and Environmental Sciences, Vol. 10(1), 2021, P 1-10

The Yamama Formation includes important carbonates reservoir that belongs to the Lower Cretaceous sequence in Southern Iraq. This study covers two oil fields (Sindbad and Siba) that are distributed Southeastern Basrah Governorate, South of Iraq. Yamama reservoir units were determined based on the study of cores, well logs, and petrographic examination of thin sections that required a detailed integration of geological data and petrophysical properties. These parameters were integrated in order to divide the Yamama Formation into six reservoir units (YA0, YA1, YA2, YB1, YB2 and YC), located between five cap rock units. The best facies association and petrophysical properties were found in the shoal environment, where the most common porosity types were the primary (interparticle) and secondary (moldic and vugs) . The main diagenetic process that occurred in YA0, YA2, and YB1 is cementation, which led to the filling of pore spaces by cement and subsequently decreased the reservoir quality (porosity and permeability). Based on the results of the final digital computer interpretation and processing (CPI) performed by using the Techlog software, the units YA1 and YB2 have the best reservoir properties. The unit YB2 is characterized by a good effective porosity average, low water saturation, good permeability, and large thickness that distinguish it from other reservoir units.

The mercury injection capillary pressure (MICP) method and nuclear magnetic resonance (NMR) relaxometry provide insight into the pore radius distribution (PRD) either of pore throats (MICP) or pore bodies (NMR) of rocks. One variety of permeability ( k) prediction models is based on the knowledge of the PRD. We have evaluated the quality of k-prediction models using a sample set of Eocene sandstones with known values of measured permeability. The Swanson method relates the apex point of the capillary pressure curve to k. Although this widely acknowledged method uses only a single point of the PRD, it provides a predictive quality with an average ratio between the measured and predicted permeability lower than a factor of three. The pore throat radius of the apex point proves to be a good proxy of the effective hydraulic radius. We determine that an improved k prediction can be achieved if a larger section of the PRD is considered in our generalized model. Using reliable values of surface relaxivity, the NMR relaxation time distribution is transformed into a PRD. We find that a characteristic apex point can be determined from NMR data, too. This characteristic point enables a good k prediction for the set of Eocene sandstone samples. In contrast to MICP, the predictive quality cannot be improved by applying an integration over a larger section of the PRD. Further tests with samples of different pore structure and lithology should demonstrate the potential of our models.

Актуальность исследования обусловлена необходимостью сокращения времени строительства скважин на арктическом шельфе ввиду ограниченного по времени сезона навигации и повышения точности при оценке запасов, получаемых по результатам испытания разведочных скважин Долгинского месторождения. Результаты исследования позволяют выбрать оптимальную технологию вскрытия карбонатных пластов-коллекторов Долгинского месторождения, дают возможность обеспечить устойчивость стенок скважины и сохранение коллекторских свойств, установить взаимосвязи коллекторских свойств пород и напряжений в продуктивных пластах, а также обосновать технологические параметры разработки месторождения. Цель: оценка влияния состава, структуры, фильтрационно-емкостных свойств пород-коллекторов и действующих напряжений на их проницаемость. Объекты: карбонатные породы-коллекторы нижнепермского и каменноугольного возраста вскрыты скважиной с глубины 2982 м до забоя 3175 м и характеризуются по керну известняками пелитоморфными, органогенно-обломочными и скрытокристаллическими разностями. Методы. Исследования проведены современными лабораторными методами, включая ртутную порометрию, метод ядерномагнитного резонанса, а также уникальный испытательный стенд Института проблем механики РАН. Результаты. На основе количественных данных литолого-петрофизических свойств изучены деформационно-прочностные характеристики пород из вероятно продуктивной части разреза скважины Северо-Долгинская № 1, которая в силу короткого сезона работ в море не испытывалась. Получены данные о структуре порового пространства, акустических свойствах, плотности, пористости и проницаемости (в том числе в пластовых условиях), остаточной водонасыщенности и т. д. Были изучены деформации образцов пород карбонатной залежи по трем направлениям и связь их с проницаемостью в условиях напряженного состояния. Полученные в результате работы новые сведения позволяют более точно подбирать свойства и компонентный состав бурового раствора с целью контроля репрессии, формирования тонкой непроницаемой фильтрационной корки и минимизации физико-химических взаимодействий между фильтратом бурового раствора и пластовыми флюидами. The relevance of the research is caused by the need to reduce well drilling time on the Arctic shelf due to the limited navigation season and increased accuracy in assessing reserves obtained from the results of testing exploratory wells at the Dolginskoe field. The research results make it possible to select the optimal technology for drilling carbonate reservoirs of the Dolginskoe field, as well as to ensure the stability of the wellbore and preserve reservoir properties, establish the relationship between reservoir properties of rocks and stresses in productive formations, and justify the technological parameters of field development. The purpose of the research is to assess the influence of the composition, structure, filtration-capacitive properties of reservoir rocks and acting stresses on their permeability. Objects. Carbonate reservoir rocks of the Lower Permian and Carboniferous age were drilled in a well from a depth of 2982 m to a bottomhole of 3175 m and are characterized by pelitomorphic limestones, organogenic-detrital and cryptocrystalline varieties. Methods. The research was carried out by modern laboratory methods, including mercury porosimetry, the method of nuclear magnetic resonance, as well as a unique test bench of the Institute for Problems in Mechanics of the Russian Academy of Sciences. Results. On the basis of quantitative data of lithological and petrophysical properties, the authors have studied the deformation and strength characteristics of rocks from the probably productive part of the section of the Severo-Dolginskaya no. 1 well, which was not tested due to the short season of offshore operations. The data were obtained on the structure of the pore space, acoustic properties, density, porosity and permeability (including in reservoir conditions), residual water saturation, etc. The deformations of samples of rocks of a carbonate deposit in three directions and their relationship with permeability under stress conditions were studied. The new information obtained as a result of the work makes it possible to more accurately select the properties and component composition of the drilling fluid in order to control the repression, the formation of a thin impermeable filter cake, and to minimize the physicochemical interactions between the mud filtrate and formation fluids.

The best petrophysical models are based on direct measurements from the core. Unfortunately, core is not available in many cases, either for economic, logistical, or historical reasons. In this study, we needed to construct a detailed Field Development Plan (FDP) for the small, marginal B-9 field in the Western Offshore Basin, India, which did not merit core acquisition. The objective is to propose a workflow for building a petrophysical model with limited data sets instead of a typical FDP workflow. After analyzing the assumptions, limitations, and uncertainties involved in the petrophysical model, we used advanced petrophysical logs to reduce uncertainty and create a robust petrophysical model. We carried out a log-based petrophysical study to determine the volume of shale, porosity, saturation, and permeability. The advanced petrophysical logs including spectroscopy, nuclear magnetic resonance (NMR), formation pressures, and well testing data are used to calibrate the petrophysical model. Spectroscopy data are used to calibrate the mineralogical volumes and grain density, whereas the porosity is calibrated from NMR data. We calibrated log-derived permeability results with NMR permeability and mobility from well test data. We used heterogeneous rock analysis on petrophysical outputs to carry out petrophysical rock typing (PRT). This has helped in establishing the porosity-permeability relationship and saturation-height model for each PRT. In the absence of irreducible water saturation ([Formula: see text]) information from the core, NMR-derived [Formula: see text] is calculated and then used to calibrate the saturation model. Log-derived permeability and saturation are estimated, which agrees well with the available testing data. This provided a robust petrophysical model that served as a basis for geologic static and reservoir dynamic models. The gas-down-to and water-up-to methods are used to establish the contacts. The resulting saturation height model agreed well with the saturations derived from the log, which gave us confidence in our dynamic model.

The more comprehensive information on the reservoir properties will help to better plan drilling and design production. Herein, diagenetic processes and geomechanical properties are notable parameters that determine reservoir quality. Recognizing the geomechanical properties of the reservoir as well as building a mechanical earth model play a strong role in the hydrocarbon reservoir life cycle and are key factors in analyzing wellbore instability, drilling operation optimization, and hydraulic fracturing designing operation. Therefore, the present study focuses on selecting the candidate zone for hydraulic fracturing through a novel approach that simultaneously considers the diagenetic, petrophysical, and geomechanical properties. The diagenetic processes were analyzed to determine the porosity types in the reservoir. After that, based on the laboratory test results for estimating reservoir petrophysical parameters, the zones with suitable reservoir properties were selected. Moreover, based on the reservoir geomechanical parameters and the constructed mechanical earth model, the best zones were selected for hydraulic fracturing operation in one of the Iranian fractured carbonate reservoirs. Finally, a new empirical equation for estimating pore pressure in nine zones of the studied well was developed. This equation provides a more precise estimation of stress profiles and thus leads to more accurate decision-making for candidate zone selection. Based on the results, vuggy porosity was the best porosity type, and zones C2, E2 and G2, having suitable values of porosity, permeability, and water saturation, showed good reservoir properties. Therefore, zone E2 and G2 were chosen as the candidate for hydraulic fracturing simulation based on their E (Young’s modulus) and ν (Poisson’s ratio) values. Based on the mechanical earth model and changes in the acoustic data versus depth, a new equation is introduced for calculating the pore pressure in the studied reservoir. According to the new equation, the dominant stress regime in the whole well, especially in the candidate zones, is SigHmax>SigV>Sighmin, while according to the pore pressure equation presented in the literature, the dominant stress regime in the studied well turns out to be SigHmax>Sighmin>SigV.

The estimation of reservoir parameters from seismic observations is one of the main objectives in reservoir characterization. However, the forward model relating the petrophysical properties of rocks to observed seismic data is highly nonlinear, and solving the relevant inverse problem is a challenging task. We have developed a novel inversion method for jointly estimating the elastic and petrophysical parameters of rocks from prestack seismic data. We combine a full rock-physics model and the exact Zoeppritz equation as the forward model. To overcome the ill conditioning of the inverse problem and address the complex prior distribution of model parameters given lithofacies variations, we have developed a regularization term based on the prior Gaussian mixture model under a Bayesian framework. The objective function is optimized by the fast simulated annealing algorithm, during which the Gaussian mixture-based regularization terms are adaptively and iteratively adjusted by the maximum likelihood estimator, allowing the posterior distribution to be more consistent with the observed seismic data. The adaptive regularization method improves the accuracy of petrophysical parameters compared with sequential inversion and nonadaptive regularization methods, and the inversion result can be used for indicating gas-saturated areas when applied to field data.

Frost damage due to freeze–thaw activity in hard rocks is a process that influences the appearance of the geo-relief of the landscape. Methods of frost damage assessment in rocks are based on parameters obtained mainly by destructive testing of samples. In this paper, nondestructive methods for the determination of pore connectivity as an important topological parameter affecting the migration of the fluid in rock material, as well as its variability due to freeze–thaw cycling, were employed. Tuff, andesite, and travertine, as well as two types of sandstones, were subjected to spontaneous imbibition testing. Based on the variation of the diffusion front with time, the slope of imbibition curve- C(I) was estimated and compared before and after 100 freeze–thaw thermal cycles. The samples were tested within a temperature range from − 10 to 10 °C in a fully saturated state in a controlled thermal chamber. Imbibition slopes were analyzed for fast (0.1–1 min) and medium (1–10 min) time intervals due to the variable petrophysical properties of the tested rocks. A considerable increase in imbibition slopes was detected, making the C(I) value a promising parameter that characterizes the interconnectivity of pores inside porous rocks. This parameter, in combination with the length of ice crystallization tc obtained from a thermistor probe located in the center of saturated dummy samples prepared from the same rock type subjected to freeze–thaw cycling, is capable of giving important indications of the degradability of rocks due to frost damage.

Background. The technology of probability petrophysical estimation of parameters using layer-bylayer interpretation of well logging data is present in this paper. Specific features of the technology is to using both the vertical and horizontal processing. Aim. The aim of the technology is the possibility of its adaptation when interpreting well logging data using the approaches of the concept of pore space connectedness, which reduce the variability of estimates of productive thicknesses of reservoirs in comparison with traditional approaches to calculating geological reserves using fixed cutoff porosity coefficient. Materials and methods. The paper discusses the main features of modeling the uncertainties of the input parameters and ways of representing them in the form of various distributions with a description of a generalized algorithm for the probabilistic assessment of geological reserves. The distributions of the reservoir area, oil density and conversion factor, the basic version of the results of the reservoir logging data interpretation in the form of a table continuous in depth with readings from the logging methods curves in intervals homogeneous in lithology are use as input parameters when executing the algorithm. In addition, distributions reflecting variations in the uncertainties of geophysical parameters, constants of petrophysical models, boundary cutoff s for identifying reservoirs and assessing their saturation nature are used to the input of the algorithm. Results. An algorithm for probabilistic petrophysical assessment has been developed taking into account the use of petrophysical modeling within the framework of the concept of pore space connectivity and the layer-by-layer mode of interpretation of well logging data. It is shown that additional petrotyping, which makes it possible to clarify the parameter of pore space connectivity, reduces the error of the resulting estimates, which can reduce the risk of making ineffective decisions. Conclusions. It is show that additional petrotyping, which makes it possible to clarify the parameter of pore space connectedness, reduces the error of the resulting estimates, which can reduce the risk of making ineffective decisions.