Relevant bibliographies by topics / Petrophysical interpretation

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Academic literature on the topic 'Petrophysical interpretation'

Author: Grafiati
Published: 4 June 2021
Last updated: 3 February 2022

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Journal articles on the topic "Petrophysical interpretation"

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Toumelin, Emmanuel, Carlos Torres-Verdin, and Nicola Bona. "Improving Petrophysical Interpretation With Wide-Band Electromagnetic Measurements." SPE Journal 13, no. 02 (June 1, 2008): 205–15. http://dx.doi.org/10.2118/96258-pa.

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Summary Because of their sensitivity to ionic content and surface texture, wide-band electromagnetic (WBEM) measurements of saturated rocks exhibit frequency dispersions of electrical conductivity and dielectric constant that are influenced by a variety of petrophysical properties. Factors as diverse as fluid saturation, porosity, pore morphology, thin wetting films, and electrically charged clays affect the WBEM response of rocks. Traditional dielectric mixing laws fail to quantitatively and practically integrate these factors to quantify petrophysical information from WBEM measurements. This paper advances a numerical proof of concept for useful petrophysical WBEM measurements. A comprehensive pore-scale numerical framework is introduced that incorporates explicit geometrical distributions of grains, fluids and clays constructed from core pictures, and that reproduces the WBEM saturated-rock response on the entire kHz-GHz frequency range. WBEM measurements are verified to be primarily sensitive (a) in the kHz range to clay amounts and wettability; (b) in the MHz range to pore morphology (i.e., connectivity and eccentricity), fluid distribution, salinity, and clay presence; and (c) in the GHz range to porosity, pore morphology and fluid saturation. Our simulations emphasize the need to measure dielectric dispersion in the entire frequency spectrum to capture the complexity of the different polarization effects. In particular, it is crucial to accurately quantify the phenomena occurring in the MHz range where pore connectivity effects are confounded with clay polarization and pore/grain shape effects usually considered in dielectric phenomena. These different sensitivities suggest a strong complementarity between WBEM and NMR measurements for improved assessments of pore-size distribution, hydraulic permeability, wettability, and fluid saturation. Introduction A number of experimental and theoretical studies suggest the measurable sensitivity of WBEM to various petrophysical factors, including porosity, brine salinity, fluid saturation and wettability, clay content, surface roughness, and even pore surface-to-volume ratio. Given the complexity of the different phenomena under consideration, practical models are designed to fit measured dielectric dispersions to ad-hoc models whose parameters are marginally supported by quantitative petrophysical concepts. Therefore, to assess whether accurate and reliable petrophysical interpretations are possible with WBEM measurements requires an analysis that (a) incorporates pore structure, pore connectivity, multiphase saturation and electrochemical effects; and (b) quantifies the contributions of each factor in the measured WBEM dispersions. However, extracting explicit petrophysical information from WBEM responses is a difficult task. Myers (1991), for instance, illustrated the non-uniqueness of WBEM measurements when a decrease of water saturation, porosity, or brine salinity yielded similar responses. Recent advances in NMR logging and interpretation (Freedman et al. 1990) can eliminate some of these ambiguities with adequate experimental conditions, and if rock wettability is known. Conversely, WBEM measurements could provide independent wettability assessment in the cases where NMR measurements alone reach their limits of sensitivity [for instance, the impact of fluid saturation history on wettability determination was studied by Toumelin et al. (2006)]. Likewise, the interpretation of NMR measurements can be biased by unaccounted rock morphology (Ramakrishnan et al. 1999) or by internal magnetic fields in shaly or iron-rich sands (Zhang et al. 2003), whereas WBEM measurements provide independent information on overall rock morphology. It is therefore timely to consider integrating both technologies for improving petrophysical analysis. The objectives of this paper are twofold:Review existing results on the extraction of petrophysical information from rock WBEM measurements, andestablish a proof of concept for the necessity to integrate electromagnetic measurements on the wide-frequency band from the kHz range to the GHz range, and study how WBEM techniques may yield petrophysical information unavailable from other in-situ measurements. To reach the second objective, we introduce a generalized pore-scale simulation framework that allows incorporating arbitrary rock morphology and multiphase fluid distribution.
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Rybakov, M., V. Goldshmidt, Y. Rotstein, L. Fleischer, and I. Goldberg. "Petrophysical constraints on gravity / magnetic interpretation in Israel." Leading Edge 18, no. 2 (February 1999): 269–72. http://dx.doi.org/10.1190/1.1438274.

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Suhail, Ahmed Abdulwahhab, Mohammed H. Hafiz, and Fadhil S. Kadhim. "Petrophysical Properties of Nahr Umar Formation in Nasiriya Oil Field." Iraqi Journal of Chemical and Petroleum Engineering 21, no. 3 (September 30, 2020): 9–18. http://dx.doi.org/10.31699/ijcpe.2020.3.2.

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Petrophysical characterization is the most important stage in reservoir management. The main purpose of this study is to evaluate reservoir properties and lithological identification of Nahr Umar Formation in Nasiriya oil field. The available well logs are (sonic, density, neutron, gamma-ray, SP, and resistivity logs). The petrophysical parameters such as the volume of clay, porosity, permeability, water saturation, were computed and interpreted using IP4.4 software. The lithology prediction of Nahr Umar formation was carried out by sonic -density cross plot technique. Nahr Umar Formation was divided into five units based on well logs interpretation and petrophysical Analysis: Nu-1 to Nu-5. The formation lithology is mainly composed of sandstone interlaminated with shale according to the interpretation of density, sonic, and gamma-ray logs. Interpretation of formation lithology and petrophysical parameters shows that Nu-1 is characterized by low shale content with high porosity and low water saturation whereas Nu-2 and Nu-4 consist mainly of high laminated shale with low porosity and permeability. Nu-3 is high porosity and water saturation and Nu-5 consists mainly of limestone layer that represents the water zone.
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Maksimova, E. N., E. G. Viktorov, E. O. Belyakov, and B. V. Belozerov. "SOCIETY OF PETROPHYSICISTS. ONLINE-PLATFORM FOR KNOWLEDGE MANAGEMENT AND SHARING." Энергия: экономика, техника, экология, no. 4 (2020): 87–92. http://dx.doi.org/10.7868/s2587739920040138.

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The geology of oilfields is becoming more complex, which leads to uncertain distribution of petrophysical properties. Quality of reservoir properties prediction depends on petrophysical models and log interpretation algorithms. It is also connected with the level of expertise of each petrophysicist as well as knowledge sharing among experts and young specialists. The aim of this paper is to present Gazprom Neft Science and Technical Centre approach to development of petrophysical competences with communities of practice.
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Heidari, Zoya, and Carlos Torres-Verdín. "Inversion-based detection of bed boundaries for petrophysical evaluation with well logs: Applications to carbonate and organic-shale formations." Interpretation 2, no. 3 (August 1, 2014): T129—T142. http://dx.doi.org/10.1190/int-2013-0172.1.

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Petrophysical interpretation of well logs acquired in organic shales and carbonates is challenging because of the presence of thin beds and spatially complex lithology; conventional interpretation techniques often fail in such cases. Recently introduced methods for thin-bed interpretation enable corrections for shoulder-bed effects on well logs but remain sensitive to incorrectly picked bed boundaries. We introduce a new inversion-based method to detect bed boundaries and to estimate petrophysical and compositional properties of multilayer formations from conventional well logs in the presence of thin beds, complex lithology/fluids, and kerogen. Bed boundaries and bed properties are updated in two serial inversion loops. Numerical simulation of well logs within both inversion loops explicitly takes into account differences in the volume of investigation of all well logs involved in the estimation, thereby enabling corrections for shoulder-bed effects. The successful application of the new interpretation method is documented with synthetic cases and field data acquired in thinly bedded carbonates and in the Haynesville shale-gas formation. Estimates of petrophysical/compositional properties obtained with the new interpretation method were compared to those obtained with (1) nonlinear inversion of well logs with inaccurate bed boundaries, (2) depth-by-depth inversion of well logs, and (3) core/x-ray diffraction measurements. Results indicated that the new method improves the estimation of porosity of thin beds by more than 200% in the carbonate field example and by more than 40% in the shale-gas example, compared to depth-by-depth interpretation results obtained with commercial software. This improvement in the assessment of petrophysical/compositional properties reduces uncertainty in hydrocarbon reserves and aids in the selection of hydraulic fracture locations in organic shale.
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Sari, Tri Wulan, and Sujito Sujito. "LITHOLOGY INTERPRETATION BASED ON WELL LOG DATA ANALYSIS IN “JS” FIELD." Applied Research on Civil Engineering and Environment (ARCEE) 1, no. 01 (October 28, 2019): 31–37. http://dx.doi.org/10.32722/arcee.v1i01.1955.

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Reservoir lithology types in a prospect zone of hydrocarbon can be known through well log data analysis, both qualitatively and quantitatively. Lithology interpretation based on qualitatively well log data analysis, has been successfully carried out by K-1 and K-3 well log data on JS Field, West Natuna basin, Riau Islands.Main focus of the research is types of lithology indicated by response the petrophysical well data log of Lower-Middle Miocene Arang Formation. Arang Formation was deposited immediately on top Barat formation and depositional environment in this formation is transitional marine - marine. Petrophysics log shows well data are log gamma ray, resistivity, neutron porosity, density, and sonic. The limitation of study are on four types lithology, they are coal, sand, sally sand, and shale. Lithology on well K-1 dominate by shale, there is thin intersection between sand and coal. The well of K-1 have sand thickest around six meter. While on well K-3 Petrophysics log data shows thin intersection between coal, sand, shaly sand, and dominated by shale. The thickest Sand have thickness 29 meter, and thicker than on K-1 well. The result in this study, the formation dominated by types of lithology “shale”.
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Ijasan, Olabode, Carlos Torres-Verdín, William E. Preeg, John Rasmus, and Edward Stockhausen. "Field examples of the joint petrophysical inversion of resistivity and nuclear measurements acquired in high-angle and horizontal wells." GEOPHYSICS 79, no. 3 (May 1, 2014): D145—D159. http://dx.doi.org/10.1190/geo2013-0355.1.

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A recently introduced interpretation workflow has confirmed that inversion-based interpretation is more reliable than conventional well-log analysis in high-angle (HA) and horizontal (HZ) wells because the former accounts for well trajectory and shoulder-bed effects on well logs. Synthetic examples show that the inversion workflow could improve the estimation of hydrocarbon volumes by 15% and 10% in HA and HZ intervals, respectively. Using field examples of thinly interbedded calcite-cemented siltstone formations, we document results of the joint petrophysical inversion of logging-while-drilling multisector nuclear (neutron porosity, density, natural gamma ray, photoelectric factor) and multiarray propagation resistivity measurement for improved formation evaluation in HA/HZ wells. Under the assumption of multilayer formation petrophysical models, the inversion approach estimates formation properties by numerically reproducing the available measurements. Subsequently, inversion-derived hydrocarbon pore volume is calculated for assessment of reservoir pay. Application of the joint inversion-based interpretation in challenging field examples highlights petrophysical characteristics such as capillary trends or water saturation variations in a hydrocarbon column influenced by reservoir quality and formation electrical anisotropy which otherwise remain inconspicuous with conventional and quick-look interpretation of well-logs.
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Yeltsov, I. N., G. V. Nesterova, and A. A. Kashevarov. "Petrophysical interpretation of time-lapse electromagnetic sounding in wells." Russian Geology and Geophysics 52, no. 6 (June 2011): 668–75. http://dx.doi.org/10.1016/j.rgg.2011.05.009.

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Heidari, Zoya, Carlos Torres-Verdín, and William E. Preeg. "Improved estimation of mineral and fluid volumetric concentrations in thinly bedded carbonate formations." GEOPHYSICS 78, no. 4 (July 1, 2013): D261—D269. http://dx.doi.org/10.1190/geo2012-0438.1.

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We recently introduced new petrophysical and compositional methods for joint interpretation of multiple conventional well logs. These inversion-based methods are suited for petrophysical interpretation of rock formations that exhibit complex solid composition, include thin beds, and are subject to mud-filtrate invasion. They combine nuclear and resistivity logs to assess porosity and volumetric/weight concentrations of mineral and fluid constituents, and are ideal for the quantitative interpretation of carbonate formations. We document the successful application of the newly introduced inversion-based interpretation methods to three carbonate formations. Interpretation results are compared to those obtained with commercial software and core/X-ray diffraction (XRD) data whenever available. For two of the carbonate field examples where XRD data are available, nonlinear joint inversion of well logs improves the assessment of porosity by more than 30% and up to 100% in the presence of thin beds when compared to conventional interpretation methods.
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Wu, Wenting, and Dario Grana. "Integrated petrophysics and rock physics modeling for well log interpretation of elastic, electrical, and petrophysical properties." Journal of Applied Geophysics 146 (November 2017): 54–66. http://dx.doi.org/10.1016/j.jappgeo.2017.09.007.

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Dissertations / Theses on the topic "Petrophysical interpretation"

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Yang, Chen. "Petrophysical and geophysical interpretation of a potential gas hydrate reservoir at Alaminos Canyon 810, northern Gulf of Mexico." The Ohio State University, 2016. http://rave.ohiolink.edu/etdc/view?acc_num=osu1480596190825913.

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Javid, Sanaz. "Petrography and petrophysical well log interpretation for evaluation of sandstone reservoir quality in the Skalle well (Barents Sea)." Thesis, Norges teknisk-naturvitenskapelige universitet, Institutt for geologi og bergteknikk, 2013. http://urn.kb.se/resolve?urn=urn:nbn:no:ntnu:diva-23137.

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39 thin sections and petrophysical log data from the Skalle well in the Hammerfest Basin, in the southwestern part of the Barents Sea, have been studied to interpret lithology, and diagenesis and their effect on the reservoir quality, and to compare reservoir properties of the different reservoir units. Petrophysical log data have been calibrated for reservoir description in cases where core material is not available. The studied formations are comprised by the Stø, Fuglen, Hekkingen, Knurr, Kolje and the Lower Kolmule Formations. The Knurr and Kolje Formations have been identified and interpreted only by wire line logs, as core material was not available for those intervals.The Lower Kolmule Formation of sandstones of lithic greywacke composition, and the Stø Formation with sandstones of subarkosic arenite composition are considered as possible reservoir rocks. All the formations are water filled which is reflected by the low resistivity logs responses. The mature sandstones of the Stø Formation show high reservoir quality (high porosity and permeability) compared to the Lower Kolmule Formation. The Hekkingen Formation is a potential source rock for the Lower Kolmule Formation, as well as a seal (cap rock) for the Stø Formation. Cementation, dissolution, compaction, clay mineral authigenesis and stylolitization are the most significant diagenetic processes affecting the reservoir quality. Some other type of processes such as glauconitization and bioturbation are also common in the studied well.
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Williams, Adrian. "Reservoir Characterization of well A-F1, Block 1, Orange Basin, South Africa." University of the Western Cape, 2018. http://hdl.handle.net/11394/6364.

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Magister Scientiae - MSc (Earth Science)
The Orange basin is relatively underexplored with 1 well per every 4000km2 with only the Ububhesi gas field discovery. Block 1 is largely underexplored with only 3 wells drilled in the entire block and only well A?F1 inside the 1500km2 3?D seismic data cube, acquired in 2009. This study is a reservoir characterization of well A?F1, utilising the acquired 3?D seismic data and re?analysing and up scaling the well logs to create a static model to display petrophysical properties essential for reservoir characterization. For horizon 14Ht1, four reservoir zones were identified, petro?physically characterized and modelled using the up scaled logs. The overall reservoir displayed average volume of shale at 24%, good porosity values between 9.8% to 15.3% and permeability between 2.3mD to 9.5mD. However, high water saturation overall which exceeds 50% as per the water saturation model, results in water saturated sandstones with minor hydrocarbon shows and an uneconomical reservoir.
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Díaz, da Jornada Ana Carolina López. "Interpretação de perfis elétricos na caracterização dos reservatórios de Camisea, Peru." reponame:Biblioteca Digital de Teses e Dissertações da UFRGS, 2008. http://hdl.handle.net/10183/13709.

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A seqüência mesozóica da bacia de Ucayali é a maior produtora de gás e condensado do Peru. A área do trabalho, denominada Grande Camisea, fica na parte sul da bacia e, na atualidade, pertence à companhia Plupetrol Peru Corporation. Neste trabalho, foi aplicado um método de interpretação de perfis de indução em um poço petrolífero no sector San Martin do campo Camisea (QuickLook Interpretation method). O objetivo consiste na caracterização do reservatório de San Martín utilizando um método de interpretação rápida de perfis elétricos e, assim, fornecer uma visão geral no entendimento de parâmetros de poços e reservatórios, de zonas produtivas e suas características petrofísicas de porosidade e de saturação do óleo. Para validar a interpretação, foram utilizadas a descrição geológica de testemunhos e amostras de calha, descrição e informação do sistema petrolífero do campo e a geologia regional da zona de interesse da bacia. Desta forma, foi possível apresentar uma comparação entre os valores obtidos através dos métodos detalhados executados pela Pluspetrol e o método rápido de interpretação aplicado aqui, assim como o desvio entre ambos os resultados.
The Mesozoic sequence of the Ucayali basin is the main producer of gas and condensate of Peru. The work area is called Gran Camisea, located in the south part of the basin, and, in the present time, belongs to the company Plupetrol Peru Corporation. In this work, a well log interpretation method was used in a gas well in San Martin area, part of the Camisea field. The goal is the characterization of the reservoir of San Martín using a Quick Look log interpretation method, and thus to supply a general view in the understanding of well and reservoirs parameters, productive zones and its petrophysics characteristics of porosity and saturation. To validate the interpretation, besides using the geologic description of well cores and cutting sampling, it was used the description and information of the petroleum system of Camisea gas field and its regional geology. It was possible to present a comparison between Pluspetrol values, obtained through detailed methods, and those from the Quick Look log interpretation method used here, as well as an analysis of convergence between both results.
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Alborzi, Mahmood. "Application of neural networks to real-time log interpretation in oil well drilling." Thesis, Brunel University, 1996. http://ethos.bl.uk/OrderDetails.do?uin=uk.bl.ethos.309502.

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Mabona, Nande Ingrid. "Application of petrophysics and seismic in reservoir characterization. A case study on selected wells, in the Orange Basin, South Africa." Thesis, University of the Western Cape, 2012. http://hdl.handle.net/11394/4380.

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>Magister Scientiae - MSc
The evaluation of petroleum reservoirs has shifted from single approach to an integrated approach. The integration, analysis and understanding of all available data from the well bore and creating property models is an exceptional way to characterize a reservoir. Formulating, implementing, and demonstrating the applicability of the joint inversion of seismic and well-bore related observations, and the use of information about the relationship between porosity and permeability as the key parameters for identifying the rock types and reservoir characterization is a vital approach in this study. Correlating well and seismic data, potential reservoirs can be delineated and important horizons (markers) can be pointed out to better characterize the reservoir. This thesis aims to evaluate the potential petroleum reservoirs of the Wells K-A1, K-A2, K-A3 and K-H1 of the Shungu Shungu field in the Orange Basin through the integration and comparison of results from core analysis, wireline logs and seismic and attempt to produce a good reservoir model and by additionally utilizing Petrophysics and seismic and trying to better understand why the area has dry wells. Different rock types that comprise reservoir and non reservoirs are identified in the study and five Facie types are distinguished. Tight, fine grained sandstones with low porosity values ranging from 3% - 6% where dominant in the targeted sandstone layers. Porosity values ranging from 11% - 18% where identified in the massive sandstone lithologies which where hosted by Well’s K-A2 and K-A3. Low permeability values reaching 0.1mD exist throughout the study area. Areas with high porosity also host high water saturation values ranging from 70 – 84%. An improvement in the porosity values at deeper zones (3700m -3725m) and is apparent. Poroperm plots exhibit quartz cemented sandstones and density with neutron plot suggest that the sandstones in the area contain quarts and dolomite mineralization.Well K-A3, consist of a cluster by quartzitic sandstone, meaning there is a large amount of sandstone present. There are apparent high porosity values around the sandstone. What is apparent from this plot is that there are many clusters that are scattered outside the chart. This could suggest some gas expulsions within this Well. Sandstones within the 14B2t1 to 14At1 interval are less developed in the vicinity covered by well K-A2 than at the K-A1 well location. The main targeted sandstones belong to the lower cretaceous and lie just below 13At1. The four wells drilled in this area are dry wells. The areas/blocks surrounding this area have shown to possess encouraging gas shows and a comparative study could reveal better answers. At deeper zones of the well at an interval of 5350m -5750m, there are more developed sandstones with good porosity values. The volume of shale is low and so is the water saturation. The main target sandstones in the study area are the Lower Cretaceous sandstones which are at an interval 13At1. These sandstones are not well developed but from the property model of the target surface it can be seen that the porosity values are much more improved than the average values applied on all the zones on the 3D grid.
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Paganoni, Matteo. "Controls on the distribution of gas hydrates in sedimentary basins." Thesis, University of Oxford, 2017. https://ora.ox.ac.uk/objects/uuid:6887b849-5668-4510-bc15-c416044dd043.

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Natural gas hydrates store a substantial portion of the Earth's organic carbon, although their occurrence is restricted by thermobaric boundaries and the availability of methane-rich fluids. The complexity of geological systems and the multiphase flow processes promoting hydrate formation can result in a mismatch between the predicted and the observed hydrate distribution. The purpose of this research is to achieve a better comprehension of the factors that influence the distribution of gas hydrates and the mechanism of fluid movements beneath and across the gas hydrate stability zone (GHSZ). Therefore, this study integrates seismic, petrophysical and geochemical data from different gas hydrate provinces. This work provides evidence that hydrates can occur below bottom-simulating reflectors, in the presence of sourcing thermogenic hydrocarbons. The relationship between fluid-escape pipes and gas hydrates is further explored, and pipe-like features are suggested to host a significant volume of hydrates. The host lithology also represents a critical factor influencing hydrate and free gas distribution and, in evaluating a natural gas hydrate system, needs to be considered in conjunction with the spatial variability in the methane supply. The three-dimensional distribution of gas hydrate deposits in coarse-grained sediments, representing the current target for hydrate exploration, is shown to be correlated with that of the underlying free gas zone, reflecting sourcing mechanisms dominated by a long-range advection. In such systems, the free gas invasion into the GHSZ appears controlled by the competition between overpressure and sealing capacity of the gas hydrate-bearing sediments. Globally, the thickness of the free gas zones is regulated by the methane supply and by different multi-phase flow processes, including fracturing, capillary invasion and possibly diffusion. In conclusion, this research indicates that geological, fluid flow and stability factors interweave at multiple scales in natural gas hydrate systems.
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Butterfield, Andrei. "Characterization of a Utica Shale Reflector Package Using Well Log Data and Amplitude Variation with Offset Analysis." Wright State University / OhioLINK, 2014. http://rave.ohiolink.edu/etdc/view?acc_num=wright1401462908.

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Adiguna, Haryanto. "Comparative study for the interpretation of mineral concentrations, total porosity, and TOC in hydrocarbon-bearing shale from conventional well logs." 2012. http://hdl.handle.net/2152/20053.

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The estimation of porosity, water saturation, kerogen concentration, and mineral composition is an integral part of unconventional shale reservoir formation evaluation. Porosity, water saturation, and kerogen content determine the amount of hydrocarbon-in-place while mineral composition affects hydro-fracture generation and propagation. Effective hydraulic fracturing is a basic requirement for economically viable flow of gas in very-low permeability shales. Brittle shales are favorable for initiation and propagation of hydraulic fracture because they require marginal or no plastic deformation. By contrast, ductile shales tend to oppose fracture propagation and can heal hydraulic fractures. Silica and carbonate-rich shales often exhibit brittle behavior while clay-rich shales tend to be ductile. Many operating companies have turned their attention to neutron capture gamma-ray spectroscopy (NCS) logs for assessing in-situ mineral composition. The NCS tool converts the energy spectrum of neutron-induced captured gamma-rays into relative elemental yields and subsequently transforms them to dry-weight elemental fractions. However, NCS logs are not usually included in a well-logging suite due to cost, tool availability, and borehole conditions. Conventional well logs are typically acquired as a minimum logging program because they provide geologists and petrophysicists with the basic elements for tops identification, stratigraphic correlation, and net-pay determination. Most petrophysical interpretation techniques commonly used to quantify mineral composition from conventional well logs are based on the assumption that lithology is dominated by one or two minerals. In organic shale formations, these techniques are ineffective because all well logs are affected by large variations of mineralogy and pore structure. Even though it is difficult to separate the contribution from each mineral and fluid component on well logs using conventional interpretation methods, well logs still bear essential petrophysical properties that can be estimated using an inversion method. This thesis introduces an inversion-based workflow to estimate mineral and fluid concentrations of shale gas formations using conventional well logs. The workflow starts with the construction and calibration of a mineral model based on core analysis of crushed samples and X-Ray Diffraction (XRD). We implement a mineral grouping approach that reduces the number of unknowns to be estimated by the inversion without loss of accuracy in the representation of the main minerals. The second step examines various methods that can provide good initial values for the inversion. For example, a reliable prediction of kerogen concentration can be obtained using the ΔlogR method (Passey et al., 1990) as well as an empirical correlation with gamma-ray or uranium logs. After the mineral model is constructed and a set of initial values are established, nonlinear joint inversion estimates mineral and fluid concentrations from conventional well logs. An iterative refinement of the mineral model can be necessary depending on formation complexity and data quality. The final step of the workflow is to perform rock classification to identify favorable production zones. These zones are selected based on their hydrocarbon potential inferred from inverted petrophysical properties. Two synthetic examples with known mineral compositions and petrophysical properties are described to illustrate the application of inversion. The impact of shoulder-bed effects on inverted properties is examined for the two inversion modes: depth-by-depth and layer-by-layer. This thesis also documents several case studies from Haynesville and Barnett shales where the proposed workflow was successfully implemented and is in good agreement with core measurements and NCS logs. The field examples confirm the accuracy and reliability of nonlinear inversion to estimate porosity, water saturation, kerogen concentration, and mineral composition.
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Ijasan, Olabode. "Inversion-based petrophysical interpretation of logging-while-drilling nuclear and resistivity measurements." 2013. http://hdl.handle.net/2152/21390.

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Undulating well trajectories are often drilled to improve length exposure to rock formations, target desirable hydrocarbon-saturated zones, and enhance resolution of borehole measurements. Despite these merits, undulating wells can introduce adverse conditions to the interpretation of borehole measurements which are seldom observed in vertical wells penetrating horizontal layers. Common examples are polarization horns observed across formation bed boundaries in borehole resistivity measurements acquired in highly-deviated wells. Consequently, conventional interpretation practices developed for vertical wells can yield inaccurate results in HA/HZ wells. A reliable approach to account for well trajectory and bed-boundary effects in the petrophysical interpretation of well logs is the application of forward and inverse modeling techniques because of their explicit use of measurement response functions. The main objective of this dissertation is to develop inversion-based petrophysical interpretation methods that quantitatively integrate logging-while-drilling (LWD) multi-sector nuclear (i.e., density, neutron porosity, photoelectric factor, natural gamma ray) and multi-array propagation resistivity measurements. Under the assumption of a multi-layer formation model, the inversion approach estimates formation properties specific to a given measurement domain by numerically reproducing the available measurements. Subsequently, compositional multi-mineral analysis of inverted layer-by-layer properties is implemented for volumetric estimation of rock and fluid constituents. The most important prerequisite for efficient petrophysical inversion is fast and accurate forward models that incorporate specific measurement response functions for numerical simulation of LWD measurements. In the nuclear measurement domain, first-order perturbation theory and flux sensitivity functions (FSFs) are reliable and accurate for rapid numerical simulation. Albeit efficient, these first-order approximations can be inaccurate when modeling neutron porosity logs, especially in the presence of borehole environmental effects (tool standoff or/and invasion) and across highly contrasting beds and complex formation geometries. Accordingly, a secondary thrust of this dissertation is the introduction of two new methods for improving the accuracy of rapid numerical simulation of LWD neutron porosity measurements. The two methods include: (1) a neutron-density petrophysical parameterization approach for describing formation macroscopic cross section, and (2) a one-group neutron diffusion flux-difference method for estimating perturbed spatial neutron porosity fluxes. Both methods are validated with full Monte Carlo (MC) calculations of spatial neutron detector FSFs and subsequent simulations of neutron porosity logs in the presence of LWD azimuthal standoff, invasion, and highly dipping beds. Analysis of field and synthetic verification examples with the combined resistivity-nuclear inversion method confirms that inversion-based estimation of hydrocarbon pore volume in HA/HZ wells is more accurate than conventional well-log analysis. Estimated hydrocarbon pore volume from conventional analysis can give rise to errors as high as 15% in undulating HA/HZ intervals.
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Books on the topic "Petrophysical interpretation"

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Doveton, John H. Principles of Mathematical Petrophysics. Oxford University Press, 2014. http://dx.doi.org/10.1093/oso/9780199978045.001.0001.

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The pioneering work of Gus Archie moved log interpretation into log analysis with the introduction of the equation that bears his name. Subsequent developments have mixed empiricism, physics, mathematical algorithms, and geological or engineering models as methods applied to petrophysical measurements in boreholes all over the world. Principles of Mathematical Petrophysics reviews the application of mathematics to petrophysics in a format that crystallizes the subject as a subdiscipline appropriate for the workstations of today. The subject matter is of wide interest to both academic and industrial professionals who work with subsurface data applied to energy, hydrology, and environmental issues. This book is the first of its kind, in that it addresses mathematical petrophysics as a distinct discipline. Other books in petrophysics are either extensive descriptions of tool design or interpretation techniques, typically in an ad hoc treatment. It covers mathematical methods that are applied to borehole and core petrophysical measurements to estimate rock properties of fluid saturation, pore types, permeability, mineralogy, facies, and reservoir characterization. These methods are demonstrated by a variety of case studies and summaries of applications. Principles of Mathematical Petrophysics is an invaluable resource for all people working with data related to petrophysics.
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Book chapters on the topic "Petrophysical interpretation"

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Herianto, Putra, Muhammad Fadhil, Suci Handayani Qolbi, Mohammad Risyad, and Beiruny Syam. "Naturally Fractured Basement Reservoir Potential Quantification from Fracture Model and Petrophysical Analysis by Leveraging Geostatistics and Seismic Interpretation: A Case Study in Jabung Block, South Sumatra Basin." In Springer Series in Geomechanics and Geoengineering, 360–68. Cham: Springer International Publishing, 2018. http://dx.doi.org/10.1007/978-3-319-99670-7_45.

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Onajite, Enwenode. "Seismic petrophysics and petrophysical well curves analysis for quantitative seismic interpretation." In Applied Techniques to Integrated Oil and Gas Reservoir Characterization, 233–48. Elsevier, 2021. http://dx.doi.org/10.1016/b978-0-12-817236-0.00008-x.

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"Geological and Petrophysical Interpretation of Logging Measurements." In Methods in Experimental Physics, 19–61. Elsevier, 1986. http://dx.doi.org/10.1016/b978-0-12-691390-3.50006-5.

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Tathed, Pratiksha, and Siddharth Misra. "Petrophysical models for the interpretation of electromagnetic logs." In Multifrequency Electromagnetic Data Interpretation for Subsurface Characterization, 71–90. Elsevier, 2021. http://dx.doi.org/10.1016/b978-0-12-821439-8.00010-0.

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Sánchez-Delgado, N., A. Rodríguez-Rey, L. Calleja, V. de Argandoña, and C. Camino. "Petrophysical interpretation of mechanical behaviour of ornamental stones from Galicia (Spain)." In Rock Engineering and Rock Mechanics: Structures in and on Rock Masses, 257–60. CRC Press, 2014. http://dx.doi.org/10.1201/b16955-41.

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Tiab, Djebbar, and Erle C. Donaldson. "Basic Well-Log Interpretation." In Petrophysics, 803–27. Elsevier, 2012. http://dx.doi.org/10.1016/b978-0-12-383848-3.00012-8.

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"Chapter 1: Petrophysics of Siliciclastic Rocks." In Seismic Petrophysics in Quantitative Interpretation, 1–28. Society of Exploration Geophysicists, 2016. http://dx.doi.org/10.1190/1.9781560803256.ch1.

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"Chapter 2: Pore Pressure and Stress State." In Seismic Petrophysics in Quantitative Interpretation, 29–42. Society of Exploration Geophysicists, 2016. http://dx.doi.org/10.1190/1.9781560803256.ch2.

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"Chapter 3: Seismic Rock Properties and Rock Physics." In Seismic Petrophysics in Quantitative Interpretation, 43–86. Society of Exploration Geophysicists, 2016. http://dx.doi.org/10.1190/1.9781560803256.ch3.

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"Chapter 4: AVO Analysis: Rock-physics Basis." In Seismic Petrophysics in Quantitative Interpretation, 87–104. Society of Exploration Geophysicists, 2016. http://dx.doi.org/10.1190/1.9781560803256.ch4.

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Conference papers on the topic "Petrophysical interpretation"

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Kolomytsev, Alexander, Ekaterina Sazonova, Ekaterina Ageeva, Yulia Pronyaeva, Alexey Pashynsky, Ilya Kneller, and Inna Evdokimova. "3D Petrophysical Interpretation of Horizontal Wells." In SPE Annual Technical Conference and Exhibition. Society of Petroleum Engineers, 2018. http://dx.doi.org/10.2118/191478-ms.

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Khoshbakht, F. "Importance of Blocking in Petrophysical Interpretation." In 7th EAGE Saint Petersburg International Conference and Exhibition. Netherlands: EAGE Publications BV, 2016. http://dx.doi.org/10.3997/2214-4609.201600254.

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Krief, M. "Petrophysical interpretation of P- and S-wave velocities." In EAGE/SEG Research Workshop 1990. European Association of Geoscientists & Engineers, 1990. http://dx.doi.org/10.3997/2214-4609.201411889.

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Simoes, Vanessa, Patrick Machado, Austin Boyd, Giovanna Carneiro, Anna Paula Duarte, Marianna Dantas, Lin Liang, et al. "Multi physics measurements integration for improving petrophysical interpretation." In International Congress of the Brazilian Geophysical Society&Expogef. Brazilian Geophysical Society, 2019. http://dx.doi.org/10.22564/16cisbgf2019.282.

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Kozhevnikov, Dmitry, and Kazimir Kovalenko. "Petrophysical Invariance Principle in Adaptive Well Log Interpretation." In SPE Russian Oil and Gas Conference and Exhibition. Society of Petroleum Engineers, 2010. http://dx.doi.org/10.2118/135977-ms.

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Nguyen, H. A., A. The Vu, and T. Thanh Nguyen. "Integrated Petrophysical Interpretation of Fractured Granite Basement Reservoirs." In 80th EAGE Conference and Exhibition 2018. Netherlands: EAGE Publications BV, 2018. http://dx.doi.org/10.3997/2214-4609.201800958.

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Kozhevnikov, Dmitry, and Kazimir Kovalenko. "Petrophysical Invariance Principle in Adaptive Well Log Interpretation (Russian)." In SPE Russian Oil and Gas Conference and Exhibition. Society of Petroleum Engineers, 2010. http://dx.doi.org/10.2118/135977-ru.

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Alsaif, Sarah F., Ali M. Alkhatib, and Alberto F. Marsala. "Enhanced Petrophysical Interpretation of 3D Electromagnetic Surveys for Reservoir Characterization." In SPE Kingdom of Saudi Arabia Annual Technical Symposium and Exhibition. Society of Petroleum Engineers, 2016. http://dx.doi.org/10.2118/182768-ms.

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Dobróka, M., P. N. Szabó, B. Kiss, and T. Krasznavölgyi. "Petrophysical Interpretation of Well Log Data Using VFSA-I2 Algorithm." In 67th EAGE Conference & Exhibition. European Association of Geoscientists & Engineers, 2005. http://dx.doi.org/10.3997/2214-4609-pdb.1.p215.

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Miotti, F. M. "Using Dempster-Shafer Theory to Model Uncertainty in Petrophysical Interpretation." In 82nd EAGE Annual Conference & Exhibition. European Association of Geoscientists & Engineers, 2020. http://dx.doi.org/10.3997/2214-4609.202012145.

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Reports on the topic "Petrophysical interpretation"

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Carlos Torres-Verdin and Mrinal K. Sen. INTEGRATED APPROACH FOR THE PETROPHYSICAL INTERPRETATION OF POST- AND PRE-STACK 3-D SEISMIC DATA, WELL-LOG DATA, CORE DATA, GEOLOGICAL INFORMATION AND RESERVOIR PRODUCTION DATA VIA BAYESIAN STOCHASTIC INVERSION. Office of Scientific and Technical Information (OSTI), March 2004. http://dx.doi.org/10.2172/825256.

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Carlos Torres-Verdin and Mrinal K. Sen. INTEGRATED APPROACH FOR THE PETROPHYSICAL INTERPRETATION OF POST-AND PRE-STACK 3-D SEISMIC DATA, WELL-LOG DATA, CORE DATA, GEOLOGICAL INFORMATION AND RESERVOIR PRODUCTION DATA VIA BAYESIAN STOCHASTIC INVERSION. Office of Scientific and Technical Information (OSTI), September 2004. http://dx.doi.org/10.2172/837074.

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