Relevant bibliographies by topics / Petrophysical propertie

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Academic literature on the topic 'Petrophysical propertie'

Author: Grafiati
Published: 22 February 2023

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Journal articles on the topic "Petrophysical propertie"

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Yogi, Ade. "Petrophysics Analysis for Reservoir Characterization of Cretaceous Clastic Rocks: A Case Study of the Arafura Basin." Jurnal Geologi dan Sumberdaya Mineral 21, no. 3 (August 28, 2020): 129. http://dx.doi.org/10.33332/jgsm.geologi.v21i3.527.

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This study presents petrophysics analysis results from two wells located in the Arafura Basin. The analysis carried out to evaluate the reservoir characterization and its relationship to the stratigraphic sequence based on log data from the Koba-1 and Barakan-1 Wells. The stratigraphy correlation section of two wells depicts that in the Cretaceous series a transgression-regression cycle. The petrophysical parameters to be calculated are the shale volume and porosity. The analysis shows that there is a relationship between stratigraphic sequences and petrophysical properties. In the study area, shale volumes used to make complete rock profiles in wells assisted by biostratigraphic data, cutting descriptions, and core descriptions. At the same time, porosity shows a conformity pattern with the transgression-regression cycle.Keywords: petrophysics, reservoir characterization, Cretaceous, transgressive-regressive cycle
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Grana, Dario, and Ernesto Della Rossa. "Probabilistic petrophysical-properties estimation integrating statistical rock physics with seismic inversion." GEOPHYSICS 75, no. 3 (May 2010): O21—O37. http://dx.doi.org/10.1190/1.3386676.

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A joint estimation of petrophysical properties is proposed that combines statistical rock physics and Bayesian seismic inversion. Because elastic attributes are correlated with petrophysical variables (effective porosity, clay content, and water saturation) and this physical link is associated with uncertainties, the petrophysical-properties estimation from seismic data can be seen as a Bayesian inversion problem. The purpose of this work was to develop a strategy for estimating the probability distributions of petrophysical parameters and litho-fluid classes from seismics. Estimation of reservoir properties and the associated uncertainty was performed in three steps: linearized seismic inversion to estimate the probabilities of elastic parameters, probabilistic upscaling to include the scale-changes effect, and petrophysical inversion to estimate the probabilities of petrophysical variables andlitho-fluid classes. Rock-physics equations provide the linkbetween reservoir properties and velocities, and linearized seismic modeling connects velocities and density to seismic amplitude. A full Bayesian approach was adopted to propagate uncertainty from seismics to petrophysics in an integrated framework that takes into account different sources of uncertainty: heterogeneity of the real data, approximation of physical models, measurement errors, and scale changes. The method has been tested, as a feasibility step, on real well data and synthetic seismic data to show reliable propagation of the uncertainty through the three different steps and to compare two statistical approaches: parametric and nonparametric. Application to a real reservoir study (including data from two wells and partially stacked seismic volumes) has provided as a main result the probability densities of petrophysical properties and litho-fluid classes. It demonstrated the applicability of the proposed inversion method.
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Bosch, Miguel, Carla Carvajal, Juan Rodrigues, Astrid Torres, Milagrosa Aldana, and Jesús Sierra. "Petrophysical seismic inversion conditioned to well-log data: Methods and application to a gas reservoir." GEOPHYSICS 74, no. 2 (March 2009): O1—O15. http://dx.doi.org/10.1190/1.3043796.

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Hydrocarbon reservoirs are characterized by seismic, well-log, and petrophysical information, which is dissimilar in spatial distribution, scale, and relationship to reservoir properties. We combine this diverse information in a unified inverse-problem formulation using a multiproperty, multiscale model, linking properties statistically by petrophysical relationships and conditioning them to well-log data. Two approaches help us: (1) Markov-chain Monte Carlo sampling, which generates many reservoir realizations for estimating medium properties and posterior marginal probabilities, and (2) optimization with a least-squares iterative technique to obtain the most probable model configuration. Our petrophysical model, applied to near-vertical-anglestackedseismic data and well-log data from a gas reservoir, includes a deterministic component, based on a combination of Wyllie and Wood relationships calibrated with the well-log data, and a random component, based on the statistical characterization of the deviations of well-log data from the petrophysical transform. At the petrophysical level, the effects of porosity and saturation on acoustic impedance are coupled; conditioning the inversion to well-log data helps resolve this ambiguity. The combination of well logs, petrophysics, and seismic inversion builds on the corresponding strengths of each type of information, jointly improving (1) cross resolution of reservoir properties, (2) vertical resolution of property fields, (3) compliance to the smooth trend of property fields, and (4) agreement with well-log data at well positions.
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Al-Mamouri, Abdullah, Amer Al-Khafaji, and Ali Al-Musawi. "The Asmari Formation Petrophysical Parameters in the Abu Ghirab Oil Field of the Zagros Fold Belt Basin, Southeastern Iraq, Using Well Log Data Interpretation." Iraqi Geological Journal 55, no. 2E (November 30, 2022): 128–39. http://dx.doi.org/10.46717/igj.55.2e.8ms-2022-11-22.

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The current study represents the evaluation of petrophysical characteristics, lithological analysis, and identification of the Asmari Formation for the main and sub-reservoir units in the Abu Ghirab oil field, Maysan, southeast of Iraq. This petrophysical assessment was accomplished using the interpretations of well log data to know the properties of the Asmari Formation reservoir. The available logs such as resistivity, gamma ray, neutron and density logs were converted to digital data using the Diger Sotware. The lithic properties of the reservoir like porosity, total shale saturation, oil and water saturation were interpreted and calculated using the interactive petrophysics software. The lithic and mineral study was completed and the type of mineral filling was known through the cross-plot of the porosity logs for different wells. The petrophysical properties were calculated and represented on the CPI profile. Depending on the petrophysical characteristics, the Asmari Formation was divided into main and sub units, which are: Jeribe-Euphrates and its sub-units A1, A2, and A3; Upper Kirkuk unit and B1, B2, B3, B4 sub-units; and Middle-Lower Kirkuk unit and C subunit. The results showed that the reservoir has economic oil productivity. The subunits B2, B3 in Upper Kirkuk were characterized by high effective porosity values and high hydrocarbon content, and they are the highest produced units in Upper Kirkuk in studied wells. The vary on lithology represents as dolomites in the Jeribe, Euphrates, limestones in the Kirkuk group, and the mineral components were calcite and dolomite.
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Astic, Thibaut, Lindsey J. Heagy, and Douglas W. Oldenburg. "Petrophysically and geologically guided multi-physics inversion using a dynamic Gaussian mixture model." Geophysical Journal International 224, no. 1 (August 21, 2020): 40–68. http://dx.doi.org/10.1093/gji/ggaa378.

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SUMMARY In a previous paper, we introduced a framework for carrying out petrophysically and geologically guided geophysical inversions. In that framework, petrophysical and geological information is modelled with a Gaussian mixture model (GMM). In the inversion, the GMM serves as a prior for the geophysical model. The formulation and applications were confined to problems in which a single physical property model was sought, and a single geophysical data set was available. In this paper, we extend that framework to jointly invert multiple geophysical data sets that depend on multiple physical properties. The petrophysical and geological information is used to couple geophysical surveys that, otherwise, rely on independent physics. This requires advancements in two areas. First, an extension from a univariate to a multivariate analysis of the petrophysical data, and their inclusion within the inverse problem, is necessary. Secondly, we address the practical issues of simultaneously inverting data from multiple surveys and finding a solution that acceptably reproduces each one, along with the petrophysical and geological information. To illustrate the efficacy of our approach and the advantages of carrying out multi-physics inversions coupled with petrophysical and geological information, we invert synthetic gravity and magnetic data associated with a kimberlite deposit. The kimberlite pipe contains two distinct facies embedded in a host rock. Inverting the data sets individually, even with petrophysical information, leads to a binary geological model: background or undetermined kimberlite. A multi-physics inversion, with petrophysical information, differentiates between the two main kimberlite facies of the pipe. Through this example, we also highlight the capabilities of our framework to work with interpretive geological assumptions when minimal quantitative information is available. In those cases, the dynamic updates of the GMM allow us to perform multi-physics inversions by learning a petrophysical model.
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Ahmed, Rayan. "Geological Model for Mauddud Reservoir Khabaz Oil Field." Iraqi Geological Journal 54, no. 1D (April 30, 2021): 29–42. http://dx.doi.org/10.46717/igj.54.1d.3ms-2021-04-23.

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The Mauddud reservoir, Khabaz oil field which is considered one of the main carbonate reservoirs in the north of Iraq. Recognizing carbonate reservoirs represents challenges to engineers because reservoirs almost tend to be tight and overall heterogeneous. The current study concerns with geological modeling of the reservoir is an oil-bearing with the original gas cap. The geological model is establishing for the reservoir by identifying the facies and evaluating the petrophysical properties of this complex reservoir, and calculate the amount of hydrocarbon. When completed the processing of data by IP interactive petrophysics software, and the permeability of a reservoir was calculated using the concept of hydraulic units then, there are three basic steps to construct the geological model, starts with creating a structural, facies and property models. The reservoirs were divided into four zones depending on the variation of petrophysical properties (porosity and permeability). Nine wells that penetrate the Cretaceous Formation (Mauddud reservoir) are included to construct the geological model. Zone number three characterized as the most important due to it Is large thickness which is about 108 m and good petrophysical properties are about 13%, 55 md, 41% and 38% for porosity, permeability, water saturation and net to gross respectively. The initial oil and gas in place are evaluated to be about 981×106 STB and 400×109 SCF.
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Hassane, Amadou, Chukwuemeka Ngozi Ehirim, and Tamunonengiyeofori Dagogo. "Rock physics diagnostic of Eocene Sokor-1 reservoir in Termit subbasin, Niger." Journal of Petroleum Exploration and Production Technology 11, no. 9 (August 20, 2021): 3361–71. http://dx.doi.org/10.1007/s13202-021-01259-2.

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AbstractEocene Sokor-1 reservoir is intrinsically heterogeneous and characterized by low-contrast low-resistivity log responses in parts of the Termit subbasin. Discriminating lithology and fluid properties using petrophysics alone is complicated and undermines reservoir characterization. Petrophysics and rock physics were integrated through rock physics diagnostics (RPDs) modeling for detailed description of the reservoir microstructure and quality in the subbasin. Petrophysical evaluation shows that Sokor-1 sand_5 interval has good petrophysical properties across wells and prolific in hydrocarbons. RPD analysis revealed that this sand interval could be best described by the constant cement sand model in wells_2, _3, _5 and _9 and friable sand model in well_4. The matrix structure varied mostly from clean and well-sorted unconsolidated sands as well as consolidated and cemented sandstones to deteriorating and poorly sorted shaly sands and shales/mudstones. The rock physics template built based on the constant cement sand model for representative well_2 diagnosed hydrocarbon bearing sands with low Vp/Vs and medium-to-high impedance signatures. Brine shaly sands and shales/mudstones were diagnosed with moderate Vp/Vs and medium-to-high impedance and high Vp/Vs and medium impedance, respectively. These results reveal that hydrocarbon sands and brine shaly sands cannot be distinctively discriminated by the impedance property, since they exhibit similar impedance characteristics. However, hydrocarbon sands, brine shaly sands and shales/mudstones were completely discriminated by characteristic Vp/Vs property. These results demonstrate the robust application of rock physics diagnostic modeling in quantitative reservoir characterization and may be quite useful in undrilled locations in the subbasin and fields with similar geologic settings.
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Il’chenko, Vadim L., and Maria A. Gannibal. "Elastic Anisotropy and Internal Structure of Rocks from the Uranium Ore Occurrences of the Litsa Ore Area (Kola Region, Russia)." Geosciences 9, no. 7 (June 28, 2019): 284. http://dx.doi.org/10.3390/geosciences9070284.

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A relation of uranium mineralization to structural, textural and physical properties of rocks was investigated using two uranium ore occurrences (Beregovoe and Dikoe) in the Litsa ore area (Kola region, Russia) as an example. Study of the rock samples collected on the surface was carried out using X-ray computer tomography (CT), petrography and petrophysics. Petrophysical properties (density and elastic anisotropy index) as well as petrographic characteristics of 25 rock samples were studied; six samples from this collection were studied by CT method. The samples from the Beregovoe site display general positive correlation between magnitude of the elastic anisotropy index and uranium concentration. The samples from the Dikoe ore occurrence, however, do not follow this trend. Comparison of CT data with that obtained from petrophysical measurements shows that the elastic anisotropy index can be low in highly deformed rock, if microfractures and micropores were sealed with secondary (including uranium) minerals; while the uneven distribution of the heavy mineral phases in weakly deformed rock can significantly increase its elastic anisotropy. The CT method combined with petrographic and petrophysical methods has proved to be useful for studying ore deposits. In particular, the CT method allows the influence of spatial variations of minerals of different specific weight on the elastic properties of rocks (elastic anisotropy) to be ascertained. The data obtained for the Litsa area suggest the course of further research involving the construction of geological structural models of the crust blocks with subsequent selection of areas with the most favorable conditions for the formation of uranium ore.
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Li, Kun, Xingyao Yin, Zhaoyun Zong, and Dario Grana. "Estimation of porosity, fluid bulk modulus, and stiff-pore volume fraction using a multitrace Bayesian amplitude-variation-with-offset petrophysics inversion in multiporosity reservoirs." GEOPHYSICS 87, no. 1 (November 18, 2021): M25—M41. http://dx.doi.org/10.1190/geo2021-0029.1.

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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.
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Astic, Thibaut, Dominique Fournier, and Douglas W. Oldenburg. "Joint inversion of potential-fields data over the DO-27 kimberlite pipe using a Gaussian mixture model prior." Interpretation 8, no. 4 (October 12, 2020): SS47—SS62. http://dx.doi.org/10.1190/int-2019-0283.1.

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We have carried out petrophysically and geologically guided inversions (PGIs) to jointly invert airborne and ground-based gravity data and airborne magnetic data to recover a quasi-geology model of the DO-27 kimberlite pipe in the Tli Kwi Cho (also referred to as TKC) cluster. DO-27 is composed of three main kimberlite rock types in contact with each other and embedded in a granitic host rock covered by a thin layer of glacial till. The pyroclastic kimberlite (PK), which is diamondiferous, and the volcanoclastic kimberlite (VK) have anomalously low density, due to their high porosity, and weak magnetic susceptibility. They are indistinguishable from each other based upon their potential-field responses. The hypabyssal kimberlite (HK), which is not diamondiferous, has been identified as highly magnetic and remanent. Quantitative petrophysical signatures for each rock unit are obtained from sample measurements, such as the increasing density of the PK/VK unit with depth and the remanent magnetization of the HK unit, and are represented as a Gaussian mixture model (GMM). This GMM guides the PGI toward generating a 3D quasi-geology model with physical properties that satisfies the geophysical data sets and the petrophysical signatures. Density and magnetization models recovered individually yield volumes that have physical property combinations that do not conform to any known petrophysical characteristics of the rocks in the area. A multiphysics PGI addresses this problem by using the GMM as a coupling term, but it puts a volume of the PK/VK unit at a location that is incompatible with geologic information from drillholes. To conform to that geologic knowledge, a fourth unit is introduced, PK-minor, which is petrophysically and geographically distinct from the main PK/VK unit. This inversion produces a quasi-geology model that presents good structural locations of the diamondiferous PK unit and can be used to provide a resource estimate or decide the locations of future drillholes.
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Dissertations / Theses on the topic "Petrophysical propertie"

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Hartigan, David Anthony. "The petrophysical properties of shale gas reservoirs." Thesis, University of Leicester, 2015. http://hdl.handle.net/2381/32213.

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A significant challenge to the petrophysical evaluation of shale gas systems can be attributed to the conductivity behaviour of clay minerals. This is compounded by centimetre to sub-millimetre vertical and lateral heterogeneity in formation geological and therefore petrophysical properties. Despite this however, we remain reliant on Archie based methods for determining water saturation (Sw), and hence the free gas saturation (1-Sg) in shale gas systems. There is however significant uncertainty in both how resistivity methods are applied and the saturation estimates they produce, due largely as Archie parameter inputs (e.g. a, m, n, and Rw) are difficult to determine in shale gas systems, where obtaining a water sample, or carrying out laboratory experiments on recovered core is often technically impractical. This research assesses the geological implications for, and controls on, variations in pseudo Archie parameters in the Bossier and Haynesville Shale Formations in the northern Gulf of Mexico basin. Investigation has particularly focused on the numerical analysis and systematic modification of Archie parameter values to minimise the error between core SW (Dean Stark analysis) and computed Sw values. Results show that the use of optimised Archie parameters can be effective in predicting SW, particularly in the Haynesville formation, but identifies systematic bias in generated Archie parameters that precludes their accurate physical interpretation. Analysis also suggests that variability in the resistivity (Rt) log response is the principal source of error in Sw estimates in the Bossier Shale. Moreover, results suggest that where clay volume exceeds 28%, the resistivity response becomes increasingly variable and elevated, indicating an apparent clay associated ‘excess resistivity’. This is explained by a geologically consistent model that links increasing clay volume to bulk pore water freshening, supported by empirical adaptations that allow for improved Archie parameter selection and a further reduction in the error of Sw estimates.
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Yang, Huade. "Relationships between petrophysical properties and petrographic properties of reservoir rocks /." Digital version accessible at:, 1999. http://wwwlib.umi.com/cr/utexas/main.

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Fitch, Peter James Rowland. "Heterogeneity in the petrophysical properties of carbonate reservoirs." Thesis, University of Leicester, 2011. http://hdl.handle.net/2381/10262.

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In comparison to sandstone reservoirs, carbonate exploration is commonly more challenging because of intrinsic heterogeneities, occurring at all scales of observation and measurement. Heterogeneity in carbonates can be attributed to variable lithology, chemistry/mineralogy, pore types, pore connectivity, and sedimentary facies. These intrinsic complexities can be related to geological processes controlling carbonate production and deposition, and to changes during their subsequent diagenesis. The term 'heterogeneity' is rarely defined and almost never numerically quantified in petrophysical analysis although it is widely stated that carbonate heterogeneities are poorly understood. This work has investigated how heterogeneity can be defined and how we can quantify this term by describing a range of statistical heterogeneity measures (e.g. Lorenz and Dykstra-Parsons coefficients). These measures can be used to interpret variation in wireline log data, allowing for comparison of their heterogeneities within individual and multiple reservoir units. Through this investigation, the Heterogeneity Log has been developed by applying these techniques to wireline log data, over set intervals of 10, 5, 2 and 1m, through a carbonate reservoir. Application to petrophysical rock characterisation shows a strong relationship to underlying geological heterogeneities in carbonate facies, mud content and porosity. Zones of heterogeneity identified through the successions show strong correlation to fluid flow zones. By applying the same statistical measures of heterogeneity to established flow zones it is possible to rank these units in terms of their internal heterogeneity. Both increased and decreased heterogeneity is documented with high reservoir quality in different wireline measurements, this can be related to underlying geological heterogeneities. Heterogeneity Logs can be used as a visual indicator of where to focus sampling strategies to ensure intrinsic variabilities are captured.
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Berhanu, Solomon Assefa. "Seismic and petrophysical properties of carbonate reservoir rocks." Thesis, University of Reading, 1994. http://ethos.bl.uk/OrderDetails.do?uin=uk.bl.ethos.262633.

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Hennah, Stephen James. "Broadband acoustic attenuation and its relationships with petrophysical properties." Thesis, University of Reading, 2003. http://ethos.bl.uk/OrderDetails.do?uin=uk.bl.ethos.408329.

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Shar, Abdul Majeed. "Petrophysical properties of fault rock : implications for petroleum production." Thesis, University of Leeds, 2015. http://etheses.whiterose.ac.uk/10434/.

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Faults can have significant impact on reservoir productivity. Understanding the factors that controls the fluid flow properties of fault rocks provides a sound basis to assess the impact of faults on reservoirs productivity. Therefore, different aspects that affect the fluid flow within siliciclastic fault formations were investigated in this research project. Fault rock samples from a number of locations were analysed including: (i) core samples from central and southern North Sea fields; (ii) and outcrop samples from the 90 Fathom fault, Northumberland, UK and Miri airport road exposure, Malaysia as well as the Hopeman fault from Invernesshire, UK. The impact of faults on fluid flow was assessed by integrating the data from QXRD analysis, microstructural examination, X-ray tomography, mercury porosimetry for pore size distribution, absolute and relative permeability measurements as well as capillary pressure tests. Single phase and multiphase flow properties which were conducted at a range of stresses are the most comprehensive collection of high quality fault rock data. The permeability measurements made using gas gave higher values than with brine, which in turn gave higher values that when measured using distilled water permeability. The differences in permeability could be the results of clay particles swelling; mobilisation and retaining within the confined pore throats, although these effects depend on the rock mineralogy and pore fluid composition. Moreover, the permeability stress sensitivity was investigated. The results showed that at low confining stresses the permeability of the fault rock core samples showed high sensitivity to stress, whereas at higher confining stresses the permeability was less pronounced to stress. This might be due to the core damage effects and the microfractures formed due to stress release, which were observed from SEM images. The pore radius calculated from gas slippage parameters at low confining pressures was in the same order of magnitude as the micro fracture width. The micro cracks could be easily closed due to stress increase hence resulted in reduction of permeability. Overall, the stress sensitivity of fault rocks from outcrop is less than that from core. This is consistent with the idea that stress sensitivity is mainly the result of the presence of grain boundary microfractures formed as core is brought to the surface. This indicates that permeability measurements made on outcrop samples may be more reliable. Another key finding was that the published permeability data (e.g. Fisher and Knipe, 2001) compared with present study data which is obtained at in-situ stress using formation compatible brines showed that the published data may not be inaccurate as the use of distilled water gives lower permeability than brines and low stresses resulted in higher permeability than in-situ stress measurements. Therefore, the results indicate that two different laboratory practices used in previous studies partially cancel each other out so that the existing data is yet valuable. The effective gas permeability were also measured at a range of stresses and it was observed that the samples with lower absolute permeabilities were more stress sensitive to stress than high permeable samples. The relative permeability results obtained were incorporated into a specific example of synthetic reservoir model. These suggested that faults formed within low permeability sands might act as a barrier to fluid flow.
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Beloborodov, Roman. "Compaction Trends of Shales: Rock Physics and Petrophysical Properties." Thesis, Curtin University, 2017. http://hdl.handle.net/20.500.11937/68259.

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Shale is the most abundant and the least known type of sedimentary rock. It is found in every basin associated with hydrocarbon depositions and is notorious for its complicated properties. This thesis is dedicated to investigation of the compaction trends of rock physics and petrophysical properties of shale. It is supplemented with in-depth analysis of shale microstructure as a key parameter controlling the macroscopic anisotropic properties of shale.
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Calleja, Glecy School of Biological Earth &amp Environmental Sciences UNSW. "Influence of mineralogy on petrophysical properties of petroleum reservoir beds." Awarded by:University of New South Wales. School of Biological, Earth and Environmental Sciences, 2005. http://handle.unsw.edu.au/1959.4/22423.

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Key petrophysical properties of reservoir sequences are determined by their individual mineral compositions, and are routinely evaluated through the analysis of cores and geophysical well logs. However, mineralogical studies are seldom incorporated in reservoir assessment. The objectives of the study were to investigate the influence of mineralogy on petrophysical properties of petroleum reservoir beds and the application of mineralogical studies in reservoir evaluation. Mineralogical analyses were performed on core samples from the Plover Formation, the principal reservoir sequence in the Northwest Shelf area of Australia, intersected in two separate wells in the Laminaria petroleum field. The techniques used included X-ray powder and oriented-aggregate analysis, optical microscopy and whole rock geochemistry. Quantification of each mineral phase based on whole-rock powder data was performed using the Rietveld-based Siroquant technique. Results from the Siroquant assay were used as an indicator of mineralogy for the individual samples and were compared with core plug and geophysical log data. X-ray micro-tomography analysis of selected samples was also performed. The reservoir sequences in both wells were sand-dominated, consisted mostly of quartz, clay mineral matrix and cement of silica, pyrite or calcite. The abundance of clay minerals increased in the shale and shaly sandstone intervals. Comparison of mineralogical and core plug analyses of samples from the same depths showed that the down-hole variations in porosity, permeability, grain density and radioactivity were accompanied by changes in mineralogy. Higher proportion of clay minerals in shales was indicated by higher gamma log signals. The gamma log may be taken as an indicator of shaliness only in intervals where kaolinite is proportional to the quantity of illitic clays. Sonic log and neutron log porosity values are comparable with core plug porosity data in sandstone intervals. However, clay minerals increase the sonic log response, thereby increasing porosity in shaly intervals. Clay minerals tend to decrease the neutron log response causing higher porosity indication in shales, similar to that expected in sandstones. Routine density log analysis underestimated porosity values because of the contribution of dense minerals to the bulk density of the formation. Use of laboratory determined grain and fluid densities resulted in improved density log porosity compared to core porosity. X-ray tomography analysis revealed an overall positive correlation between mineralogy and porosity data. Routine geophysical log evaluation revealed inconsistent results when compared to core analysis data because of the influence of minerals on various logs. It is essential that mineralogical studies be included in reservoir assessment. X-ray tomography may provide an alternative approach in evaluating porosity and mineralogy.
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Moore, Julian Kenneth Spencer. "Integration of the sedimentological and petrophysical properties of mudstone samples." Thesis, University of Newcastle Upon Tyne, 2005. http://hdl.handle.net/10443/227.

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Mudstones are of considerable scientific and economic importance as they are the dominant sedimentary rock type, forming the main repository of Earth history and having significance to numerous aspects of petroleum exploration and production, and many other industries. This study investigated the sedimentological characteristics of 150 diverse mudstone samples. The novel integration of grain size analysis combined with petrographic observations lead to a framework in which six mudstone grain size distribution (GSD) types are defined. The grain size types proposed are remarkably consistent in their form and characteristics and can be understood in terms of well constrained physical processes of deposition. The basis for this definition reflects largely the relative contributions of a flocculated, clay-rich component and an unflocculated silt/sand-rich grain size component. Integration of grain size data, pore size data and petrographic observations suggests a critical division between: (a) flocdominated mudrocks whose structure is supported by the clay matrix; and (b) silt-rich mudrocks whose structure is supported by a silt/fine sand framework. Floc-dominated mudrocks with clay matrix support develop low permeabilities and become very good capillary seals at relatively shallow depths. In contrast, silt-rich mudrocks with framework support only become low permeability units and very good capillary seals at much greater levels of compaction. The framework proposed here can form the basis of predictive flow and seal capacity models for mudrocks. A combined PCAcluster analysis approach to the grain size based classification of mudstones showed that of the six types defined in Chapter 2, types 1 — 4 (floc — silt mixtures) were consistently partitioned from types 5 — 6 (silt or sand rich mixtures). An attempt was made to quantify the distribution of key pore parameters, such as mean pore size, by grouping the data to reflect the matrix (grain size types 1 — 4) and framework (grain size types 5 — 6) support regimes and dividing into 5% porosity bins. The statistical distribution of pore network properties could not be verified, principally due to a combination of sparse sample numbers and highly variable nature of this data. This work illustrates that variability in mudstone pore size distributions is not constrained solely by lithology (support regime) and porosity, and thus that other factors must be taken into account if their evolution during compaction is to be understood.
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Haines, Thomas J. "The evolution of petrophysical properties across carbonate hosted normal fault zones." Thesis, University of Aberdeen, 2014. http://digitool.abdn.ac.uk:80/webclient/DeliveryManager?pid=225315.

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Books on the topic "Petrophysical propertie"

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Schön, Jürgen H. Physical properties of rocks: Fundamentals and principles of petrophysics. New York: Pergamon, 1996.

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Schön, Jürgen. Physical properties of rocks: Fundamentals and principles of petrophysics. Oxford, OX, UK: Pergamon, 1996.

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M, Goolsby Steven, Longman Mark W, and Rocky Mountain Association of Geologists., eds. Occurrence and petrophysical properties of carbonate reservoirs in the Rocky Mountain region. Denver, Colo: Rocky Mountain Association of Geologists, 1988.

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C, Donaldson Erle, ed. Petrophysics: Theory and practice of measuring reservoir rock and fluid transport properties. 2nd ed. Boston: Gulf Professional Pub., 2004.

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Tiab, Djebbar. Petrophysics: Theory and practice of measuring reservoir rock and fluid transport properties. Houston, Tex: Gulf Pub. Co., 1996.

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C, Donaldson Erle, ed. Petrophysics: Theory and practice of measuring reservoir rock and fluid transport properties. 3rd ed. Amsterdam: Gulf Professional Pub., 2012.

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Tiab, Djebbar. Petrophysics: Theory and practice of measuring reservoir rock and fluid transport properties ; solutions manual. Houston, Tex: Gulf Pub. Co., 1997.

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Crysdale, Bonnie L. Bitumen-bearing deposits of the United States: A summary of the locations, resources, and petrophysical properties of bitumen-bearing rocks in the United States. [Washington, D.C.]: U.S. G.P.O., 1988.

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Crysdale, Bonnie L. Bitumen-bearing deposits of the United States: A summary of the locations, resources, and petrophysical properties of bitumen-bearing rocks in the United States. Washington, DC: Dept. of the Interior, 1988.

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Crysdale, Bonnie L. Heavy oil resources of the United States: A summary of the locations, resources, and petrophysical properties of heavy oil reservoirs in the conterminous United States. Washington, DC: Dept. of the Interior, 1990.

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Book chapters on the topic "Petrophysical propertie"

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Lucia, F. Jerry. "Petrophysical Rock Properties." In Carbonate Reservoir Characterization, 1–22. Berlin, Heidelberg: Springer Berlin Heidelberg, 1999. http://dx.doi.org/10.1007/978-3-662-03985-4_1.

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Lucia, F. Jerry. "Erratum to: Petrophysical Rock Properties." In Carbonate Reservoir Characterization, 227. Berlin, Heidelberg: Springer Berlin Heidelberg, 1999. http://dx.doi.org/10.1007/978-3-662-03985-4_9.

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Azevedo, Leonardo, and Amílcar Soares. "Deriving Petrophysical Properties with Seismic Inversion." In Geostatistical Methods for Reservoir Geophysics, 91–107. Cham: Springer International Publishing, 2017. http://dx.doi.org/10.1007/978-3-319-53201-1_5.

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Yang, Shenglai. "Other Physical Properties of Reservoir Rocks." In Fundamentals of Petrophysics, 297–313. Berlin, Heidelberg: Springer Berlin Heidelberg, 2016. http://dx.doi.org/10.1007/978-3-662-53529-5_7.

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Yang, Shenglai. "Other Physical Properties of Reservoir Rocks." In Fundamentals of Petrophysics, 297–313. Berlin, Heidelberg: Springer Berlin Heidelberg, 2017. http://dx.doi.org/10.1007/978-3-662-55029-8_7.

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Yang, Shenglai. "Chemical Composition and Properties of Reservoir Fluids." In Fundamentals of Petrophysics, 3–26. Berlin, Heidelberg: Springer Berlin Heidelberg, 2016. http://dx.doi.org/10.1007/978-3-662-53529-5_1.

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Yang, Shenglai. "Natural Gas Physical Properties Under High Pressure." In Fundamentals of Petrophysics, 27–74. Berlin, Heidelberg: Springer Berlin Heidelberg, 2016. http://dx.doi.org/10.1007/978-3-662-53529-5_2.

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Yang, Shenglai. "Chemical Composition and Properties of Reservoir Fluids." In Fundamentals of Petrophysics, 3–26. Berlin, Heidelberg: Springer Berlin Heidelberg, 2017. http://dx.doi.org/10.1007/978-3-662-55029-8_1.

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Yang, Shenglai. "Natural Gas Physical Properties Under High Pressure." In Fundamentals of Petrophysics, 27–74. Berlin, Heidelberg: Springer Berlin Heidelberg, 2017. http://dx.doi.org/10.1007/978-3-662-55029-8_2.

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Yang, Shenglai. "Physical Properties of Reservoir Fluids Under Reservoir Conditions." In Fundamentals of Petrophysics, 135–77. Berlin, Heidelberg: Springer Berlin Heidelberg, 2016. http://dx.doi.org/10.1007/978-3-662-53529-5_4.

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Conference papers on the topic "Petrophysical propertie"

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Fleury, Marc. "NMR Relaxation and Petrophysical Properties." In MAGNETIC RESONANCE IN POROUS MEDIA: Proceedings of the 10th International Bologna Conference on Magnetic Resonance in Porous Media (MRPM10), including the 10th Colloquium on Mobile Magnetic Resonance (CMMR10). AIP, 2011. http://dx.doi.org/10.1063/1.3562221.

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Zamirian, M., K. Aminian, and S. Ameri. "Measuring Marcellus Shale Petrophysical Properties." In SPE Western Regional Meeting. Society of Petroleum Engineers, 2016. http://dx.doi.org/10.2118/180366-ms.

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Zamirian, Mehrdad, Kashy Aminian, and Samuel Ameri. "Measurement of Key Shale Petrophysical Properties." In SPE Annual Technical Conference and Exhibition. Society of Petroleum Engineers, 2015. http://dx.doi.org/10.2118/174968-ms.

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Bahar, Asnul, and Mohan Kelkar. "Integrated Lithofacies and Petrophysical Properties Simulation." In SPE Western Regional Meeting. Society of Petroleum Engineers, 1997. http://dx.doi.org/10.2118/38261-ms.

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Dey‐Sarkar, S. K., and C. F. James. "Prestack analysis: Relevance of petrophysical properties." In SEG Technical Program Expanded Abstracts 1986. Society of Exploration Geophysicists, 1986. http://dx.doi.org/10.1190/1.1893096.

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Ohenhen, I., O. A. Olafuyi, and S. S. Ikiensikimama. "Petrophysical Properties of Nigeria Tarsand Revisited." In SPE Nigeria Annual International Conference and Exhibition. Society of Petroleum Engineers, 2015. http://dx.doi.org/10.2118/178413-ms.

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Suri, Yatin. "Predicting petrophysical properties using SEM Image." In SPE Reservoir Characterisation and Simulation Conference and Exhibition. Society of Petroleum Engineers, 2011. http://dx.doi.org/10.2118/144434-ms.

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Narasimhan, Santhosh, Kim Long Nguyen, Naveen Verma, Mahmoud Fawzy Fahmy, Rasha Al-Morakhi, Meshael Jumah, Riyad Quttainah, et al. "Importance of Multi-Domain Integration in Selection of a Proper Landing Point for Unconventional Horizontal Drilling and Completions." In SPE Annual Technical Conference and Exhibition. SPE, 2022. http://dx.doi.org/10.2118/210086-ms.

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Abstract Historically, understanding and selecting a successful landing point candidate for horizontal drilling and fracturing was mostly performed based on a single-domain perspective or purely based on geoscience data sets. On the other hand, this paper proposes an unconventional multi-domain integration for shale oil and shale gas development for successful drilling and completions. In heterogeneous formations where organic-rich rocks are the source and reservoir, the geology and petrophysics along with engineering integration is a must for short- and long-term production and optimization. In this unconventional approach, petrophysical and 1D mechanical earth models were developed using triple combo (TCOM) and sonic by integrating in-situ core measurements to narrow down the uncertainty in the flow and mechanical properties. In the standard approach, landing points are mostly selected by looking for good petrophysical reservoir units with good porosity, good organics and low water saturation. However, these good petrophysical-rich rocks could be geomechanically highly stressed (both total and effective) and less brittle. Completion engineers mostly prefer to drill and frac low stress and brittle facies. This is because brittle rocks with proppant in the fractures can keep the fracs open for a longer time without getting into the embedment issues as a result of production. If embedment becomes an issue as a result of depletion in the highly stressed landed horizontal wells, then there is a possibility for significant drop in production sharply in short time. In this paper a few potential reservoir units are selected as landing points for horizontal drilling based on petrophysical derivatives followed by the geomechanical attributes of good brittle and low stress of the reservoir sections within the Najmah (NJW) and Sargelu (SRW) formations. For each landing point, frac modeling was performed to obtain height and length. Geometries from each landing point are different due to vertical geomechanical heterogeneity. These vertical stacking patterns for facies and properties combined with a certain completion design will determine the fracture propagation and pinch points vs. barriers. Generated frac heights from each landing point will be compared with petrophysics to understand the thickness of organic-rich intervals vs. water content. Based on the initial geometries from each landing point, completion optimization was performed by altering the rate vs. volume pumped to understand the variations in fracture height and length. This is to illustrate the completion vs. production cost economics based on single well modeling. Since Najmah (NJW) - Sargelu (SRW) organic-rich source reservoirs in Kuwait are in early appraisal phase, the data set lacks pressure and production history. Hence the validation of frac geometries is not discussed.
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Wang, Zhijing, W. K. Hirsche, and G. E. Sedgwick. "Electrical and Petrophysical Properties of Carbonate Rocks." In SPE Annual Technical Conference and Exhibition. Society of Petroleum Engineers, 1991. http://dx.doi.org/10.2118/22661-ms.

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Peltoniemi, M., P. Jääskeläinen, R. Pietilä, L. Kivekäs, and A. Niemi. "Petrophysical Properties of Nickel Deposits in Finland." In 59th EAGE Conference & Exhibition. European Association of Geoscientists & Engineers, 1997. http://dx.doi.org/10.3997/2214-4609-pdb.131.gen1997_p066.

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Reports on the topic "Petrophysical propertie"

1

Scromeda, N., S. Connell, and T. J. Katsube. Petrophysical properties of mineralized and nonmineralized rocks from Giant and Con mine areas, Northwest Territories. Natural Resources Canada/ESS/Scientific and Technical Publishing Services, 2000. http://dx.doi.org/10.4095/211604.

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Hu, K., and P. Hannigan. Reservoir petrophysical property evaluation from well logs for the Mackenzie Corridor, Northern Mainland, Canada. Natural Resources Canada/ESS/Scientific and Technical Publishing Services, 2009. http://dx.doi.org/10.4095/248032.

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McDowell, S. D. Geothermal alteration of sediments in the Salton Sea scientific drill hole: Petrophysical properties and mass changes during alteration: Final report. Office of Scientific and Technical Information (OSTI), December 1987. http://dx.doi.org/10.2172/5434885.

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Enkin, R. J., D. Cowan, J. Tigner, A. Severide, D. Gilmour, A. Tkachyk, M. Kilduff, and J. Baker. Physical property measurements at the GSC paleomagnetism and petrophysics laboratory, including Electric Impedance Spectrum methodology and analysis. Natural Resources Canada/ESS/Scientific and Technical Publishing Services, 2012. http://dx.doi.org/10.4095/291564.

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Uchida, T., T. Tsuji, T. Takahashi, T. Okui, and H. Minagawa. Petrophysical properties and sedimentology of gas-hydrate-bearing sediments in the JAPEX/JNOC/GSC et al. Mallik 5L-38 gas hydrate production research well. Natural Resources Canada/ESS/Scientific and Technical Publishing Services, 2005. http://dx.doi.org/10.4095/220733.

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Chidsey, Thomas C., David E. Eby, Michael D. Vanden Berg, and Douglas A. Sprinkel. Microbial Carbonate Reservoirs and Analogs from Utah. Utah Geological Survey, July 2021. http://dx.doi.org/10.34191/ss-168.

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Multiple oil discoveries reveal the global scale and economic importance of a distinctive reservoir type composed of possible microbial lacustrine carbonates like the Lower Cretaceous pre-salt reservoirs in deepwater offshore Brazil and Angola. Marine microbialite reservoirs are also important in the Neoproterozoic to lowest Cambrian starta of the South Oman Salt Basin as well as large Paleozoic deposits including those in the Caspian Basin of Kazakhstan (e.g., Tengiz field), and the Cedar Creek Anticline fields and Ordovician Red River “B” horizontal play of the Williston Basin in Montana and North Dakota, respectively. Evaluation of the various microbial fabrics and facies, associated petrophysical properties, diagenesis, and bounding surfaces are critical to understanding these reservoirs. Utah contains unique analogs of microbial hydrocarbon reservoirs in the modern Great Salt Lake and the lacustrine Tertiary (Eocene) Green River Formation (cores and outcrop) within the Uinta Basin of northeastern Utah. Comparable characteristics of both lake environments include shallowwater ramp margins that are susceptible to rapid widespread shoreline changes, as well as compatible water chemistry and temperature ranges that were ideal for microbial growth and formation/deposition of associated carbonate grains. Thus, microbialites in Great Salt Lake and from the Green River Formation exhibit similarities in terms of the variety of microbial textures and fabrics. In addition, Utah has numerous examples of marine microbial carbonates and associated facies that are present in subsurface analog oil field cores.
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Corriveau, L., J. F. Montreuil, O. Blein, E. Potter, M. Ansari, J. Craven, R. Enkin, et al. Metasomatic iron and alkali calcic (MIAC) system frameworks: a TGI-6 task force to help de-risk exploration for IOCG, IOA and affiliated primary critical metal deposits. Natural Resources Canada/CMSS/Information Management, 2021. http://dx.doi.org/10.4095/329093.

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Australia's and China's resources (e.g. Olympic Dam Cu-U-Au-Ag and Bayan Obo REE deposits) highlight how discovery and mining of iron oxide copper-gold (IOCG), iron oxide±apatite (IOA) and affiliated primary critical metal deposits in metasomatic iron and alkali-calcic (MIAC) mineral systems can secure a long-term supply of critical metals for Canada and its partners. In Canada, MIAC systems comprise a wide range of undeveloped primary critical metal deposits (e.g. NWT NICO Au-Co-Bi-Cu and Québec HREE-rich Josette deposits). Underexplored settings are parts of metallogenic belts that extend into Australia and the USA. Some settings, such as the Camsell River district explored by the Dene First Nations in the NWT, have infrastructures and 100s of km of historic drill cores. Yet vocabularies for mapping MIAC systems are scanty. Ability to identify metasomatic vectors to ore is fledging. Deposit models based on host rock types, structural controls or metal associations underpin the identification of MIAC-affinities, assessment of systems' full mineral potential and development of robust mineral exploration strategies. This workshop presentation reviews public geoscience research and tools developed by the Targeted Geoscience Initiative to establish the MIAC frameworks of prospective Canadian settings and global mining districts and help de-risk exploration for IOCG, IOA and affiliated primary critical metal deposits. The knowledge also supports fundamental research, environmental baseline assessment and societal decisions. It fulfills objectives of the Canadian Mineral and Metal Plan and the Critical Mineral Mapping Initiative among others. The GSC-led MIAC research team comprises members of the academic, private and public sectors from Canada, Australia, Europe, USA, China and Dene First Nations. The team's novel alteration mapping protocols, geological, mineralogical, geochemical and geophysical framework tools, and holistic mineral systems and petrophysics models mitigate and solve some of the exploration and geosciences challenges posed by the intricacies of MIAC systems. The group pioneers the use of discriminant alteration diagrams and barcodes, the assembly of a vocab for mapping and core logging, and the provision of field short courses, atlas, photo collections and system-scale field, geochemical, rock physical properties and geophysical datasets are in progress to synthesize shared signatures of Canadian settings and global MIAC mining districts. Research on a metamorphosed MIAC system and metamorphic phase equilibria modelling of alteration facies will provide a foundation for framework mapping and exploration of high-grade metamorphic terranes where surface and near surface resources are still to be discovered and mined as are those of non-metamorphosed MIAC systems.
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