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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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Liu, Wei Fu, Shuang Long Liu, and Hong Ying Han. "Petrophysical Study on Carbonate Reservoir." Applied Mechanics and Materials 522-524 (February 2014): 1313–16. http://dx.doi.org/10.4028/www.scientific.net/amm.522-524.1313.
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In light of complex lithology and serious heterogeneity of carbonate reservoir, the paper presents a comprehensive study of petrophysical characteristics of it. By using available well log data and fuzzy mathematical method, a lithologic model for identification of carbonate reservoir is developed. According to recognized fractural types, a model for fractural porosity interpretation is established. By way of correction of small core sample using big sample, relationship between core porosity and effectively estimated well log porosity is built up, obtaining effective porosities. Using different fractural types and dual lateral log data, a model for fluid saturation explanation is set up. Furthermore, these models and measured information are used for feasibility evaluation of them, reaching higher consistency and satisfied results.
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Tarigan, Febrina Bunga, Ordas Dewanto, Karyanto Karyanto, Rahmat Catur Wibowo, and Andika Widyasari. "ANALISIS PETROFISIKA UNTUK MENENTUKAN OIL-WATER CONTACT PADA FORMASI TALANGAKAR, LAPANGAN “FBT”, CEKUNGAN SUMATRA SELATAN." Jurnal Geofisika Eksplorasi 5, no. 1 (January 17, 2020): 15–29. http://dx.doi.org/10.23960/jge.v5i1.20.
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In conducting petrophysics analysis, there are many methods on each property. Therefore, it is necessary to determine the exact method on each petrophysical property suitable for application in the field of research in order to avoid irregularities at the time of interpretation. The petrophysical property consists of volume shale, porosity, water saturation, etc. This research used six well data named FBT01, FBT02, FBT03, FBT04, FBT05, and FBT06 and also assisted with core data contained in FBT03. Core data used as a reference in petrophysical analysis because it was considered to have represented or closed to the actual reservoir conditions in the field. The area in this research was in Talangakar Formation, "FBT" Field, South Sumatra Basin. The most suited volume shale method for “FBT” field condition was gamma ray-neutron-density method by seeing its photo core and lithology. As for the effective porosity, the most suited method for the field was neutron-density-sonic method by its core. Oil-water contact was useful to determine the hydrocarbon reserves. Oil-water contact was obtained at a depth of 2277.5 feet on FBT01, 2226.5 feet on FBT02, 2312.5 feet on FBT03, 2331 feet on FBT04, 2296 feet on FBT05, and 2283.5 feet on FBT06. The oil-water contact depth differences at Talangakar formation in FBT field caused by structure in subsurface.
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Grana, Dario, Marco Pirrone, and Tapan Mukerji. "Quantitative log interpretation and uncertainty propagation of petrophysical properties and facies classification from rock-physics modeling and formation evaluation analysis." GEOPHYSICS 77, no. 3 (May 1, 2012): WA45—WA63. http://dx.doi.org/10.1190/geo2011-0272.1.
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Formation evaluation analysis, rock-physics models, and log-facies classification are powerful tools to link the physical properties measured at wells with petrophysical, elastic, and seismic properties. However, this link can be affected by several sources of uncertainty. We proposed a complete statistical workflow for obtaining petrophysical properties at the well location and the corresponding log-facies classification. This methodology is based on traditional formation evaluation models and cluster analysis techniques, but it introduces a full Monte Carlo approach to account for uncertainty evaluation. The workflow includes rock-physics models in log-facies classification to preserve the link between petrophysical properties, elastic properties, and facies. The use of rock-physics model predictions guarantees obtaining a consistent set of well-log data that can be used both to calibrate the usual physical models used in seismic reservoir characterization and to condition reservoir models. The final output is the set of petrophysical curves with the associated uncertainty, the profile of the facies probabilities, and the entropy, or degree of confusion, related to the most probable facies profile. The full statistical approach allows us to propagate the uncertainty from data measured at the well location to the estimated petrophysical curves and facies profiles. We applied the proposed methodology to two different well-log studies to determine its applicability, the advantages of the new integrated approach, and the value of uncertainty analysis.
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Tronicke, Jens, and Hendrik Paasche. "Integrated interpretation of 2D ground-penetrating radar, P-, and S-wave velocity models in terms of petrophysical properties: Assessing uncertainties related to data inversion and petrophysical relations." Interpretation 5, no. 1 (February 1, 2017): T121—T130. http://dx.doi.org/10.1190/int-2016-0081.1.
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Near-surface geophysical techniques are extensively used in a variety of engineering, environmental, geologic, and hydrologic applications. While many of these applications ask for detailed, quantitative models of selected material properties, geophysical data are increasingly used to estimate such target properties. Typically, this estimation procedure relies on a two-step workflow including (1) the inversion of geophysical data and (2) the petrophysical translation of the inverted parameter models into the target properties. Standard deterministic implementations of such a quantitative interpretation result in a single best-estimate model, often without considering and propagating the uncertainties related to the two steps. We address this problem by using a rather novel, particle-swarm-based global joint strategy for data inversion and by implementing Monte Carlo procedures for petrophysical property estimation. We apply our proposed workflow to crosshole ground-penetrating radar, P-, and S-wave data sets collected at a well-constrained test site for a detailed geotechnical characterization of unconsolidated sands. For joint traveltime inversion, the chosen global approach results in ensembles of acceptable velocity models, which are analyzed to appraise inversion-related uncertainties. Subsequently, the entire ensembles of inverted velocity models are considered to estimate selected petrophysical properties including porosity, bulk density, and elastic moduli via well-established petrophysical relations implemented in a Monte Carlo framework. Our results illustrate the potential benefit of such an advanced interpretation strategy; i.e., the proposed workflow allows to study how uncertainties propagate into the finally estimated property models, while concurrently we are able to study the impact of uncertainties in the used petrophysical relations (e.g., the influence of uncertain, user-specified parameters). We conclude that such statistical approaches for the quantitative interpretation of geophysical data can be easily extended and adapted to other applications and geophysical methods and might be an important step toward increasing the popularity and acceptance of geophysical tools in engineering practice.
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Sanuade, Oluseun Adetola, Adesoji Olumayowa Akanji, Abayomi Adesola Olaojo, and Kehinde David Oyeyemi. "Seismic interpretation and petrophysical evaluation of SH field, Niger Delta." Journal of Petroleum Exploration and Production Technology 8, no. 1 (June 7, 2017): 51–60. http://dx.doi.org/10.1007/s13202-017-0363-x.
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Simoes, Vanessa, Patrick Pereira Machado, Marianna Dantas, Horrara de Freitas Diógenes Lima, and Lin Liang. "Multi-Sensor Inversion, Quantifying and Reducing Uncertainty on Petrophysical Interpretation." Rio Oil and Gas Expo and Conference 20, no. 2020 (December 1, 2020): 78–79. http://dx.doi.org/10.48072/2525-7579.rog.2020.078.
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LYSAK, Yulia, Yuriy SHPOT, Andriy SHYRA, Zoriana KUCHER, and Ihor KUROVETS. "PETROPHYSICAL MODELS OF TERRIGENOUS RESERVOIRS OF THE CARBONIFEROUS DEPOSITS OF THE CENTRAL PART OF THE DNIEPER-DONETS DEPRESSION." Geology and Geochemistry of Combustible Minerals 1, no. 178 (August 27, 2019): 63–73. http://dx.doi.org/10.15407/ggcm2019.01.063.
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The purpose of the work was to construct petrophysical models of reservoir rocks of different rank: typical and unified. Typical models describe connections between the parameters of individual rocks lithotypes occurring in definite geological conditions and serving as the basis for the development of petrophysical classification of reservoir rocks in the oil geology. The principle of unification provides for creation of the models structure for different reservoir lithotypes both in the geological section and in the area. We have studied petrophysical properties of reservoir rocks of Carboniferous deposits in the central part of the Dnieper-Donets depression. Petrophysical properties of rocks in conditions close to the formational ones and relations between them were studied on a number of samples formed by the core samples of different age. Main geological factors that have an influence on reservoir properties of rocks were taken into consideration. While constructing and analysing of petrophysical models we have used a probable-statistic approach with the use of the correlative-regressive analysis. Result of the work is contained in typical petrophysical models for individual areas and in unified models obtained on consolidated samples for Lower Carboniferous deposits of this region. Characteristic features in variations of petrophysical properties of reservoir rocks of Carboniferous deposits and their models have been ascertained. A conclusion has been made that multidimensional models, in which the depth of occurrence of deposits is one of the parameters that are necessary to consider while constructing petrophysical models, are the most informative for determination of petrophysical properties of the studied deposits, and the models obtained by us are known to be a petrophysical basis for quantitative interpretation of data from geophysical studies in the boreholes of the given region.
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Ijasan, Olabode, Carlos Torres-Verdín, and William E. Preeg. "Inversion-based petrophysical interpretation of logging-while-drilling nuclear and resistivity measurements." GEOPHYSICS 78, no. 6 (November 1, 2013): D473—D489. http://dx.doi.org/10.1190/geo2013-0175.1.
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Interpretation of borehole measurements acquired in high-angle (HA) and horizontal (HZ) wells is challenging due to the significant influence of well trajectory and bed geometrical effects. Experience shows that accurate integrated interpretation of well logs acquired in HA/HZ wells requires explicit consideration of 3D measurement physics. The most reliable alternative for interpretation of well logs in HA/HZ wells is with inversion techniques that correct measurements for shoulder-bed, undulating well trajectory, and bed geometrical effects while taking advantage of high data resolution. We discovered an efficient layer-based inversion workflow for combined, quantitative petrophysical and compositional interpretation of logging-while-drilling sector-based nuclear (density, neutron porosity, photoelectric factor, gamma ray) and array propagation resistivity measurements acquired in HA/HZ wells. A challenging synthetic benchmark example confirmed improved formation evaluation with the layer-based inversion workflow across hydrocarbon-bearing zones in HA/HZ wells, where estimated hydrocarbon pore volume and porosity increased by 10% and 15%, respectively, with respect to conventional interpretation methods. Furthermore, application of the inversion-based method to a field example of HZ well across calcite-cemented siltstone layers confirmed its advantage over conventional interpretation techniques.
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Shragge, Jeffrey, Julien Bourget, David Lumley, Jeremie Giraud, Thomas Wilson, Afzal Iqbal, Mohammad Emami Niri, et al. "The Western Australia Modeling project — Part 1: Geomodel building." Interpretation 7, no. 4 (November 1, 2019): T773—T791. http://dx.doi.org/10.1190/int-2018-0217.1.
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A key goal in industry and academic seismic research is overcoming long-standing imaging, inversion, and interpretation challenges. One way to address these challenges is to develop a realistic 3D geomodel constrained by local-to-regional geologic, petrophysical, and seismic data. Such a geomodel can serve as a benchmark for numerical experiments that help users to better understand the key factors underlying — and devise novel solutions to — these exploration and development challenges. We have developed a two-part case study on the Western Australia (WA) Modeling (WAMo) project, which discusses the development and validation of a detailed large-scale geomodel of part of the Northern Carnarvon Basin (NCB) located on WA’s North West Shelf. Based on the existing regional geologic, petrophysical, and 3D seismic data, we (1) develop the 3D geomodel’s tectonostratigraphic surfaces, (2) populate the intervening volumes with representative geologic facies, lithologies, and layering as well as complex modular 3D geobodies, and (3) generate petrophysical realizations that are well-matched to borehole observations point-wise and in terms of vertical and lateral trends. The resulting 3D WAMo geomodel is geologically and petrophysically realistic, representative of short- and long-wavefield features commonly observed in the NCB, and leads to an upscaled viscoelastic model well-suited for high-resolution 3D seismic modeling studies. In the companion paper, we study WAMo seismic modeling results that demonstrate the quality of the WAMo geomodel for generating shot gathers and migration images that are highly realistic and directly comparable with those observed in NCB field data.
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Dobróka, Mihály, Norbert Péter Szabó, József Tóth, and Péter Vass. "Interval inversion approach for an improved interpretation of well logs." GEOPHYSICS 81, no. 2 (March 1, 2016): D155—D167. http://dx.doi.org/10.1190/geo2015-0422.1.
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The quality analysis of well-logging inversion results has always been an important part of formation evaluation. The precise calculation of hydrocarbon reserves requires the most accurate possible estimation of porosity, water saturation, and shale and rock-matrix volumes. The local inversion method conventionally used to predict the above model parameters depth by depth represents a marginally overdetermined inverse problem, which is rather sensitive to the uncertainty of observed data and limited in estimation accuracy. To reduce the harmful effect of data noise on the estimated model, we have suggested the interval inversion method, in which an increase of the overdetermination ratio allows a more accurate solution of the well-logging inverse problem. The interval inversion method inverts the data set of a longer depth interval to predict the vertical distributions of petrophysical parameters in a joint inversion procedure. In formulating the forward problem, we have extended the validity of probe response functions to a greater depth interval assuming the petrophysical parameters are depth dependent, and then we expanded the model parameters into a series using the Legendre polynomials as basis functions for modeling inhomogeneous formations. We solved the inverse problem for a much smaller number of expansion coefficients than data to derive the petrophysical parameters in a stable overdetermined inversion procedure. The added advantage of the interval inversion method is that the layer thicknesses and suitably chosen zone parameters can be estimated automatically by the inversion procedure to refine the results of inverse and forward modeling. We have defined depth-dependent model covariance and correlation matrices to compare the quality of the local and interval inversion results. A detailed study using well logs measured from a Hungarian gas-bearing unconsolidated formation revealed that the greatly overdetermined interval inversion procedure can be effectively used in reducing the estimation errors in shaly sand formations, which may refine significantly the results of reserve calculation.
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White, R. E. "The accuracy of estimating Q from seismic data." GEOPHYSICS 57, no. 11 (November 1992): 1508–11. http://dx.doi.org/10.1190/1.1443218.
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A major aim of seismic interpretation is the inference of petrophysical properties of reservoir rocks. Because the inversion from seismic to petrophysical characteristics is far from unique, this task requires a range of seismic parameters, prominent among which are seismic velocity, impedance, and Poisson’s ratio. The inclusion of seismic absorption in this list could add desirable complementary information. For example, absorption may be more sensitive to clay content than seismic velocity (Klimento and McCann, 1990). However seismic absorption is difficult to measure, particularly over depth intervals as short as most reservoir intervals.
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Zhang, Yujin, Hasan Sidi, and Mark Sams. "Improving petrophysical interpretation through statistical log analysis and rock physics modeling." ASEG Extended Abstracts 2007, no. 1 (December 1, 2007): 1. http://dx.doi.org/10.1071/aseg2007ab212.
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Zeb, Jahan, Sanjeev Rajput, and Jimmy Ting. "Seismic petrophysics focused case study for AVA modelling and pre-stack seismic inversion." APPEA Journal 56, no. 1 (2016): 341. http://dx.doi.org/10.1071/aj15025.
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Hydrocarbon reservoirs are characterised by integrating seismic, well-log and petrophysical information, which are dissimilar in spatial distribution, scale and relationship to reservoir properties. Well logs are essential for amplitude versus offset (AVO) modelling and seismic inversion. The usability of well logs can be determined during wavelet estimation, seismic-to-well ties, background model building, property distribution for inversion, deriving probability density functions and variograms, offset-to-angle conversion of seismic data, and many other processes. For the implementation of seismic inversion workflows, accurate and geologically corrected compressional-sonic, shear-sonic and density logs are necessary. Preparing the logs for quantitative interpretation becomes challenging in a real-field environment because of bad borehole conditions including washouts, uncalibrated and variability of logging tools, invasion effects, missing shear logs and change of borehole size. Conventional petrophysical analysis is usually restricted to the reservoir interval, the calculation of reservoir versus non-reservoir (including sands or shales), and log corrections for smaller intervals; in contrast, seismic petrophysics encompasses the entire geological interval, calculates the volume of multi-minerals, incorporates boundaries between non-reservoir and reservoir, and often includes the prediction of missing compressional and shear-sonic for AVO analysis. A detailed seismic petrophysics analysis was performed for amplitude versus angle (AVA) modelling and attributes analysis. To perform the AVA modelling, a series of forward models in association with rock physics modelled fluid-substituted logs were developed, and associated seismic responses for various pore fluids and rock types studied. The results reveal that synthetic seismic responses together with the AVA analysis show changes for various lithologies. AVA attributes analysis show trends in generated synthetic seismic responses for various fluid-substituted and porosity logs. Reservoir modelling and fluid substitution increases understanding of the observed seismic response. This paper describes detailed data analysis using various techniques to confirm the rock model for petrophysical evaluation, rock physics modelling, AVA analysis, pre-stack seismic inversion, and the scenario modelling applied to the study of an oil field in Australia.
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Pirie, Iain, Jack Horkowitz, Gary Simpson, and John Hohman. "Advanced methods for the evaluation of a hybrid-type unconventional play: The Bakken petroleum system." Interpretation 4, no. 2 (May 1, 2016): SF93—SF111. http://dx.doi.org/10.1190/int-2015-0139.1.
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Hybrid-type plays such as the Bakken petroleum system (BPS) can be particularly challenging from an interpretation, completion, or production perspective due to the mix of conventional and unconventional elements coexisting within a relatively short depth interval. In the BPS, conventional aspects include the presence of separate reservoir intervals, which, depending on your location within the basin, may include the Scallion, Middle Bakken, Sanish, and Three Forks. Unconventional aspects include the Lower Bakken and Upper Bakken shales, which are organic-rich shales comprising source rock and reservoir. Developing an accurate petrophysical evaluation of these formations requires a priori knowledge of the mineralogy, fluids, and geomechanical properties such that appropriate logging measurements, core analysis methods, and interpretation techniques can be obtained and used. During the development phase of an oil field, the log and core measurements being acquired and the petrophysical evaluation being performed may vary significantly from well to well across the field. Some wells may have triple-combo wireline or logging-while-drilling measurements consisting of bulk density, neutron porosity, and induction or laterolog resistivity, supplemented with a total gamma ray measurement. Borehole sonic logs may also have been acquired in some wells primarily for seismic calibration, geomechanical modeling, and hydraulic stimulation design. If the “standard” suite of measurements and petrophysical evaluation being provided fail to accurately represent the true complexity of the formations being evaluated, the asset valuation will, in most cases, be negatively impacted. Our formation evaluation of the BPS led to the identification of unique petrophysical challenges for each of the formations comprising the BPS. Traditional formation evaluation methods were applied to the BPS based on triple-combo measurements, a traditional petrophysical analysis, and the evaluation of net feet of pay. Advanced evaluation methods and techniques were then applied to address the petrophysical complexities identified with core evaluation, advanced log measurements, and discrepancies between the two. New petrophysical models were developed and fine-tuned to address the shortcomings of the simple models, and the net feet of pay were reevaluated using these new models. The detailed formation evaluation program used to characterize the BPS consisted of standard triple-combo logs supplemented with advanced downhole measurements including: (1) triaxial resistivity for thin-bed analysis, (2) nuclear magnetic resonance for porosity, free-fluid, and kerogen identification, (3) dielectric dispersion for water saturation, (4) geochemical spectroscopy for mineralogy and total organic carbon, and (5) dipole sonic for dynamic rock properties. Petrophysical models were developed using deterministic and probabilistic methods to integrate the measurements acquired for the most accurate analysis of porosity, saturation, and mineralogy and to best describe the hydrocarbon production potential of the BPS.
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Yang, Qinshan, and Carlos Torres-Verdín. "Joint interpretation and uncertainty analysis of petrophysical properties in unconventional shale reservoirs." Interpretation 3, no. 1 (February 1, 2015): SA33—SA49. http://dx.doi.org/10.1190/int-2014-0045.1.
Full textAbstract:
Interpretation of hydrocarbon-bearing shale is subject to great uncertainty because of pervasive heterogeneity, thin beds, and incomplete and uncertain knowledge of saturation-porosity-resistivity models. We developed a stochastic joint-inversion method specifically developed to address the quantitative petrophysical interpretation of hydrocarbon-bearing shale. The method was based on the rapid and interactive numerical simulation of resistivity and nuclear logs. Instead of property values themselves, the estimation method delivered the a posteriori probability of each property. The Markov-chain Monte Carlo algorithm was used to sample the model space to quantify the a posteriori distribution of formation properties. Additionally, the new interpretation method allows the use of fit-for-purpose statistical correlations between water saturation, salt concentration, porosity, and electrical resistivity to implement uncertain, non-Archie resistivity models derived from core data, including those affected by total organic carbon (TOC). In the case of underdetermined estimation problems, i.e., when the number of measurements was lower than the number of unknowns, the use of a priori information enabled plausible results within prespecified petrophysical and compositional bounds. The developed stochastic interpretation technique was successfully verified with data acquired in the Barnett and Haynesville Shales. Core data (including X-ray diffraction data) were combined into a priori information for interpretation of nuclear and resistivity logs. Results consisted of mineral concentrations, TOC, and porosity together with their uncertainty. Eighty percent of the core data was located within the 95% credible interval of estimated mineral/fluid concentrations.
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Ahmad, Naveed, Sikandar Khan, Eisha Fatima Noor, Zhihui Zou, and Abdullatif Al-Shuhail. "Seismic Data Interpretation and Identification of Hydrocarbon-Bearing Zones of Rajian Area, Pakistan." Minerals 11, no. 8 (August 18, 2021): 891. http://dx.doi.org/10.3390/min11080891.
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The present study interprets the subsurface structure of the Rajian area using seismic sections and the identification of hydrocarbon-bearing zones using petrophysical analysis. The Rajian area lies within the Upper Indus Basin in the southeast (SE) of the Salt Range Potwar Foreland Basin. The marked horizons are identified using formation tops from two vertical wells. Seismic interpretation of the given 2D seismic data reveals that the study area has undergone severe distortion illustrated by thrusts and back thrusts, forming a triangular zone within the subsurface. The final trend of those structures is northwest–southeast (NW–SE), indicating that the area is part of the compressional regime. The zones interpreted by the study of hydrocarbon potential include Sakessar limestone and Khewra sandstone. Due to the unavailability of a petrophysics log within the desired investigation depths, lithology cross-plots were used for the identification of two potential hydrocarbon-bearing zones in one well at depths of 3740–3835 m (zone 1) and 4015–4100 m (zone 2). The results show that zone 2 is almost devoid of hydrocarbons, while zone 1 has an average hydrocarbon saturation of about 11%.
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Caspari, Eva, Andrew Greenwood, Ludovic Baron, Daniel Egli, Enea Toschini, Kaiyan Hu, and Klaus Holliger. "Characteristics of a fracture network surrounding a hydrothermally altered shear zone from geophysical borehole logs." Solid Earth 11, no. 3 (May 7, 2020): 829–54. http://dx.doi.org/10.5194/se-11-829-2020.
Full textAbstract:
Abstract. Hydrothermally active and altered fault/shear zones in crystalline rocks are of practical importance because of their potential similarities with petrothermal reservoirs and exploitable natural hydrothermal systems. The petrophysical and hydraulic characterization of such structures is therefore of significant interest. Here, we report the results of corresponding investigations on a prominent shear zone of this type located in the crystalline Aar massif of the central Swiss Alps. A shallow borehole was drilled, which acutely intersects the core of the shear zone and is entirely situated in its surrounding damage zone. The focus of this study is a detailed characterization of this damage zone based on geophysical borehole measurements. For this purpose, a comprehensive suite of borehole logs, comprising passive and active nuclear, full-waveform sonic, resistivity, self-potential, optical televiewer, and borehole radar data, was collected. The migrated images of the borehole radar reflection data together with the optical televiewer data reveal a complicated network of intersecting fractures in the damage zone. Consequently, the associated petrophysical properties, notably the sonic velocities and porosities, are distinctly different from intact granitic formations. Cluster analyses of the borehole logs in combination with the structural interpretations of the optical televiewer data illustrate that the variations in the petrophysical properties are predominantly governed by the intense brittle deformation. The imaged fracture network and the high-porosity zones associated with brittle deformation represent the main flow pathways. This interpretation is consistent with the available geophysical measurements as well as the analyses of the retrieved core material. Furthermore, the interpretation of the self-potential and fluid resistivity log data suggests a compartmentalized hydraulic behavior, as evidenced by inflows of water into the borehole from different sources, which is likely to be governed by the steeply dipping structures.
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Eze, C., G. Emujakporue, and DC Okujagu. "3D Petrophysical Modelling Of Queen Field, Onshore Niger Delta, Nigeria." Journal of Applied Sciences and Environmental Management 24, no. 11 (January 11, 2021): 1941–47. http://dx.doi.org/10.4314/jasem.v24i11.14.
Full textAbstract:
Petrophysical-Modelling is indispensable in upstream Projects, considering the high cost, risks and uncertainties associated with this sector. Petrophysical qualities for Queen Field was modeled using Information obtained and analyzed from well-logs and 3-D Seismic data. Coarse-grain, Medium- grain and fine-grain Sands as well as Shale were all delineated by GR log. Results of petrophysical evaluation conducted on seven reservoir intervals correlated across the field showed that; Shale volume was below 35%, Total Porosity are > 20% Effective Porosity are >15% Permeability is > 380.00mD all of this conforms to excellent reservoir quantity. Seismic interpretation showed the presence of synthetic and antithetic faults. Two horizons were mapped on seismic data and utilized for modeling. These models were the framework for facies and petrophysical properties distribution. Facies models were generated using sequential indicator simulation while petrophysical properties were generated using sequential gaussian simulation algorithm. A comparison was further done between facies constrained and non-facies constrained models. It was found that for Porosity, Permeability, Water of Saturation and Shale Volume Models not constrained to facies all showed overestimated Models, in addition Stochastic STOIIP not constrained to facies gave an Over Estimated P50 value for Surface I and O Reservoir Interval as 624.028M, 76.28MM, when compared to Stochastic Hydrocarbon STOIIP when constrained to facies that showed Stochastic P50 value of 513,247 and 67.04MM for surface I and O and Deterministic STOIIP of 742.90M and 87.88MM. This study validates the practice of constraining Petrophysical model to facies available on the field as the best practice.
Keywords: Queen Field, Onshore, Niger Delta, 3D Petrophysical.
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Wang, Fred P., F. Jerry Lucia, and Charles Kerans. "Modeling dolomitized carbonate‐ramp reservoirs: A case study of the Seminole San Andres unit—Part I, Petrophysical and geologic characterizations." GEOPHYSICS 63, no. 6 (November 1998): 1866–75. http://dx.doi.org/10.1190/1.1444479.
Full textAbstract:
Major issues in characterizing carbonate‐ramp reservoirs include geologic framework, seismic stratigraphy, interwell heterogeneity including rock fabric facies and permeability structure, and factors affecting petrophysical properties and reservoir simulation. The Seminole San Andres unit, Gaines County, West Texas, and the San Andres outcrop of Permian age in the Guadalupe Mountains, New Mexico, were selected for an integrated reservoir characterization to address these issues. The paper is divided into two parts. Part I covers petrophysical and geologic characterization, and part II describes seismic modeling, reservoir geostatistics, stochastic modeling, and reservoir simulation. In dolomitic carbonates, two major pore types are interparticle (includes intergranular and intercrystalline) and vuggy. For nonvuggy carbonates the three important petrophysical/rock fabric classes are (I) grainstone, (II) grain‐dominated packstone and medium crystalline dolostone, and (III) mud‐dominated packstone, wackestone, mudstone, and fine crystalline dolostone. Core data from Seminole showed that rock fabric and pore type have strong positive correlations with absolute and relative permeabilities, residual oil saturation, waterflood recovery, acoustic velocity, and Archie cementation exponent. Petrophysical models were developed to estimate total porosity, separate‐vug porosity, permeability, and Archie cementation exponent from wireline logs to account for effects of rock fabric and separate‐vug porosity. The detailed and regional stratigraphic models were established from outcrop analogs and applied to seismic interpretation and wireline logs and cores. The aggradational seismic character of the San Andres Formation at Seminole is consistent with the cycle stacking pattern within the reservoir. In particular, the frequent preservation of cycle‐based mudstone units in the Seminole San Andres unit is taken to indicate high accommodation associated with greater subsidence rates in this region. A model for the style of high‐frequency cyclicity and the distribution of rock‐fabric facies within cycles was developed using continuous outcrop exposures at Lawyer Canyon. This outcrop model was applied during detailed core descriptions. These, together with detailed analysis of wireline log signatures, allowed construction of the reservoir framework based on genetically and petrophysically significant high‐frequency cycles. Petrophysical properties of total and separate‐vug porosities, permeability, water saturation, and rock fabrics were calculated from wireline log data. High‐frequency cycles and rock‐fabric units are the two critical scales for modeling carbonate‐ramp reservoirs. Descriptions of rock‐fabric facies stacked within high‐frequency cycles provide the most accurate framework for constructing geologic and reservoir models. This is because petrophysical properties can be better grouped by rock fabrics than depositional facies. The permeability‐thickness ratios among these rock fabric units can then be used to approximate fluid flow and recovery efficiency.
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Han, Yifu, and Siddharth Misra. "Joint petrophysical inversion of multifrequency conductivity and permittivity logs derived from subsurface galvanic, induction, propagation, and dielectric dispersion measurements." GEOPHYSICS 83, no. 3 (May 1, 2018): D97—D112. http://dx.doi.org/10.1190/geo2017-0285.1.
Full textAbstract:
Borehole-based subsurface electromagnetic (EM) measurements, namely, galvanic resistivity (laterolog), induction, propagation, and dielectric dispersion logs, are commonly used for water-saturation estimation in hydrocarbon-bearing formations. EM logs exhibit frequency dependence due to the interfacial polarization (IP) effects arising from clay-grain surfaces, conductive minerals, and charge blockage in pore throats. IP effects in shale formations adversely affect the log-derived water-saturation estimates, especially when there is low porosity, high salinity, the presence of pyrite disseminations, and high clay concentration. Conventional EM log-interpretation methods estimate water saturation in shale formations by separately interpreting the galvanic, induction, propagation, and dielectric dispersion logs using various empirical models or mixing laws. This approach leads to significant variations and uncertainties in petrophysical estimations. We have developed an inversion-based joint petrophysical interpretation of multifrequency effective electrical conductivity and dielectric permittivity logs derived from various combinations of the four aforementioned downhole EM logs acquired in clay- and pyrite-rich shale formations. The proposed joint-interpretation method uses a single mechanistic model that accounts for the IP effect arising from clay and conductive mineral grains, thereby generating physically consistent water-saturation estimates in shales. The proposed inversion-based interpretation also generates estimates of formation brine conductivity, surface conductance of clay, and average radius of clay and conductive mineral grains. The proposed method is applied to one field case and three synthetic geologic formations, with varying clay type, conductive mineral properties, and water saturation. Further, the sensitivity of inversion-derived estimates to the presence of various types of noise in the EM logs is investigated. The joint petrophysical inversion algorithm is applied to field broadband dispersion EM data acquired in an organic-rich shale formation. Water saturation, brine conductivity, surface conductance of clay, and radius of clay were consistently estimated in the shale formation using various combinations of available EM logs.
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Wawrzyniak-Guz, Kamila. "Instantaneous Attributes Applied to Full Waveform Sonic Log and Seismic Data in Integration of Elastic Properties of Shale Gas Formations in Poland." E3S Web of Conferences 35 (2018): 03007. http://dx.doi.org/10.1051/e3sconf/20183503007.
Full textAbstract:
Seismic attributes calculated from full waveform sonic log were proposed as a method that may enhance the interpretation the data acquired at log and seismic scales. Though attributes calculated in the study were the mathematical transformations of amplitude, frequency, phase or time of the acoustic full waveforms and seismic traces, they could be related to the geological factors and/or petrophysical properties of rock formations. Attributes calculated from acoustic full waveforms were combined with selected attributes obtained for seismic traces recorded in the vicinity of the borehole and with petrophysical parameters. Such relations may be helpful in elastic and reservoir properties estimation over the area covered by the seismic survey.
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Tan, Maojin, Keyu Mao, Xiaodong Song, Xuan Yang, and Jingjing Xu. "NMR petrophysical interpretation method of gas shale based on core NMR experiment." Journal of Petroleum Science and Engineering 136 (December 2015): 100–111. http://dx.doi.org/10.1016/j.petrol.2015.11.007.
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Wollner, Uri, Humberto Arevalo-Lopez, and Jack Dvorkin. "Seismic-scale petrophysical interpretation and gas-volume estimation from simultaneous impedance inversion." Leading Edge 36, no. 11 (November 2017): 910–15. http://dx.doi.org/10.1190/tle36110910.1.
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Mollehuara Canales, R., E. Kozlovskaya, J. P. Lunkka, H. Guan, E. Banks, and K. Moisio. "Geoelectric interpretation of petrophysical and hydrogeological parameters in reclaimed mine tailings areas." Journal of Applied Geophysics 181 (October 2020): 104139. http://dx.doi.org/10.1016/j.jappgeo.2020.104139.
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Mkinga, Oras Joseph, Erik Skogen, and Jon Kleppe. "Petrophysical interpretation in shaly sand formation of a gas field in Tanzania." Journal of Petroleum Exploration and Production Technology 10, no. 3 (December 13, 2019): 1201–13. http://dx.doi.org/10.1007/s13202-019-00819-x.
Full textAbstract:
AbstractAn onshore gas field (hereafter called the R field—real name not revealed) is in the southeast coast of Tanzania which includes a Tertiary aged shaly sand formation (sand–shale sequences). The formation was penetrated by an exploration well R–X wherein no core was acquired, and there is no layer-wise published data of the petrophysical properties of the R field in the existing literature, which are essential to reserves estimation and production forecast. In this paper, the layer-wise interpretation of petrophysical properties was undertaken by using wireline logs to obtain parameters to build a reservoir simulation model. The properties extracted include shale volume, total and effective porosities, sand fractions and sand porosity, and water saturation. Shale volume was computed using Clavier equation from gamma ray. Density method was used to calculate total and effective porosities. Thomas–Stieber method was used to determine sand porosity and sand fraction, and water saturation was computed using Poupon–Leveaux model. The statistics of the parameters extracted are presented, where shale volume obtained that varies with zones is between 6 and 54% volume fraction, with both shale laminations and dispersed shale were identified. Total porosity obtained is in a range from 12 to 22%. Sand porosity varies between 15 and 25%, and sand fraction varies between 33 and 93% height fraction. Average water saturation obtained is between 32 and 49% volume fraction.
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Yang, Tao, Jintian Gao, Zuowen Gu, Baatarkhuu Dagva, and Batsaikhan Tserenpil. "Petrophysical Properties (Density and Magnetization) of Rocks from the Suhbaatar-Ulaanbaatar-Dalandzadgad Geophysical Profile in Mongolia and Their Implications." Scientific World Journal 2013 (2013): 1–12. http://dx.doi.org/10.1155/2013/791918.
Full textAbstract:
Petrophysical properties of 585 rock samples from the Suhbaatar-Ulaanbaatar-Dalandzadgad geophysical profile in Mongolia are presented. Based on the rock classifications and tectonic units, petrophysical parameters (bulk density, magnetic susceptibility, intensity of natural remanent magnetization, and Köenigsberger ratio) of these rocks are summarized. Results indicate that (1) significant density contrast of different rocks would result in variable gravity anomalies along the profile; (2) magnetic susceptibility and natural remanent magnetization of all rocks are variable, covering 5-6 orders of magnitude, which would make a variable induced magnetization and further links to complex magnetic anomalies in ground surface; (3) the distribution of rocks with different lithologies controls the pattern of lithospheric magnetic anomaly along the profile. The petrophysical database thus provides not only one of the keys to understand the geological history and structure of the profile, but also essential information for analysis and interpretation of the geophysical (e.g., magnetic and gravity) survey data.
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Osaki, Lawson Jack, Alexander Iheanyichukwu Opara, Chikwendu Njoku Okereke, Uche Petters Adiela, Ikechukwu Onyema Njoku, Theophilus Terhemba Emberga, and Ndidiamaka Eluwa. "3-D Seismic Interpretation and Volumetric Estimation of “Osaja Field” Niger Delta, Nigeria." International Letters of Natural Sciences 59 (October 2016): 14–28. http://dx.doi.org/10.18052/www.scipress.com/ilns.59.14.
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3-D seismic interpretation and petrophysical analysis of the Osaja Field, Niger Delta, was carried out with aim of carrying out a detailed structural interpretation, reservoir characterization and volumetric estimation of the field. Four wells were correlated across the field to delineate the lithology and establish the continuity of reservoir sand as well as the general stratigraphy of the area. The petrophysical analysis carried out, revealed two sand units that are hydrocarbon bearing reservoirs (Sand_A and Sand_B).The spatial variation of the reservoirs were studied on a field wide scale using seismic interpretation. Time and depth structural maps generated were used to establish the structural architecture/geometry of the prospect area of the field. The depth structure map revealed NE-SW trending anticlinal structures with F5and F6as faults assisted closures to the reservoir. Furthermore, reservoir parameters such as net pay, water saturation porosity, net-to-gross etc, were derived from the integration of seismic and well log data. The structural interpretation on the 3-D seismic data of the study area revealed a total of seven faults ranging from synthetic to antithetic faults. The petrophysical analysis gave the porosity values of the reservoir Sand_A ranging from 18.1 - 20.3% and reservoir Sand_B ranging from 13.1-14.9% across the reservoir. The permeability values of reservoir Sand_A ranging from 63-540md and reservoir Sand_B ranging from 18-80md hence there is decrease in porosity and permeability of the field with depth.The net-to-gross varies from 22.1% to 22.4% in Rerservoir Sand A to between 5.34- 12% for Rerservoir Sand _A while Sw values for the reservoirs ranges from 38-42% in well 2 to about 68.79-96.06% in well 11. The result of original oil in place for all the wells calculated revealed that well 2 has the highest value with 9.3mmbls. These results indicate that the reservoirs under consideration have a poor to fair hydrocarbon (oil) prospect.
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Handoyo, Handoyo, M. Rizki Sudarsana, and Restu Almiati. "Rock Physics Modeling and Seismic Interpretation to Estimate Shally Cemented Zone in Carbonate Reservoir Rock." Journal of Geoscience, Engineering, Environment, and Technology 1, no. 1 (December 1, 2016): 45. http://dx.doi.org/10.24273/jgeet.2016.11.6.
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Carbonate rock are important hydrocarbon reservoir rocks with complex texture and petrophysical properties (porosity and permeability). These complexities make the prediction reservoir characteristics (e.g. porosity and permeability) from their seismic properties more difficult. The goal of this paper are to understanding the relationship of physical properties and to see the signature carbonate initial rock and shally-carbonate rock from the reservoir.
To understand the relationship between the seismic, petrophysical and geological properties, we used rock physics modeling from ultrasonic P- and S- wave velocity that measured from log data. The measurements obtained from carbonate reservoir field (gas production). X-ray diffraction and scanning electron microscope studies shown the reservoir rock are contain wackestone-packstone content. Effective medium theory to rock physics modeling are using Voigt, Reuss, and Hill.
It is shown the elastic moduly proposionally decrease with increasing porosity. Elastic properties and wave velocity are decreasing proporsionally with increasing porosity and shally cemented on the carbonate rock give higher elastic properties than initial carbonate non-cemented. Rock physics modeling can separated zones which rich of shale and less of shale.
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Stadtmuller, Marek, Anita Lis-Śledziona, and Małgorzata Słota-Valim. "Petrophysical and geomechanical analysis of the Lower Paleozoic shale formation, North Poland." Interpretation 6, no. 3 (August 1, 2018): SH91—SH106. http://dx.doi.org/10.1190/int-2017-0193.1.
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The complexity of shale formation interpretation requires an accurate evaluation of a detailed petrophysical model in association with the analysis of the geomechanical properties. Mineralogy plays an important role in controlling shale’s mechanical properties, among which one of the most problematic parameters to establish is the Biot’s coefficient. Although, this parameter is necessary to determine the magnitude of the effective stresses acting in the reservoir, it is not included in the standard protocols used in Poland. This paper presents a comprehensive petrophysical and geomechanical evaluation of the unconventional reservoirs of lower Paleozoic age formation: lower Silurian and Ordovician deposits located in the onshore part of the Baltic Basin (Poland). In this study, the Biot’s coefficient from well-log data was calculated. Initially, a calibrated rock-physics model was derived to provide a set of relationships between the elastic and petrophysical properties. Based on an accurate, calibrated petrophysical model, the effective bulk modulus along with the Biot’s coefficient and horizontal stresses were calculated. Ultimately, the tectonic regime was determined. Using full-waveform sonic data analysis, the horizontal anisotropy was estimated. The directions of maximum and minimum horizontal stress were established based on several X-tended Range Micro Imager images of breakout structures and drilling-induced fractures.
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Kurgansky, V. ""GEOPHYSICAL RESEARCHES OF MINING HOLES" – 50 YEARS AT TARAS SHEVCHENKO NATIONAL UNIVERSITY OF KYIV." Visnyk of Taras Shevchenko National University of Kyiv. Geology, no. 1 (84) (2019): 89–94. http://dx.doi.org/10.17721/1728-2713.84.13.
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Development of carotage (retrospective years 1969-2019) at Taras Shevchenko National University of Kyiv is described. Basic achievements are shown in educational and scientific directions. Carbonate rocks methodology study problems, petrophysical models which allowed building physically well-founded dependences of "core-core", "core-geophysics", "geophysics- geophysics" type are described. Petrophysical simulation, theory of probability and mathematical statistics methods allowed the author to work out a complex system of data processing and interpretation in welllogging. Current status and tendency in dataware drilling process of the deep oil and gas wells are examined. Absolutely new ideology of operative getting of the reliable directional survey data without special logging services (telesystem in the process of drilling, autonomous inclinometer and other) is proposed.
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Mimoun, Jordan G., Carlos Torres-Verdín, and William E. Preeg. "Quantitative interpretation of pulsed neutron capture logs: Part 1 — Fast numerical simulation." GEOPHYSICS 76, no. 3 (May 2011): E81—E93. http://dx.doi.org/10.1190/1.3569600.
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Pulsed neutron capture (PNC) logs are commonly used for formation evaluation behind casing and to assess time-lapse variations of hydrocarbon pore volume. Because conventional interpretation methods for Σ logs assume homogeneous formations, errors may arise, especially in thinly bedded formations, when appraising petrophysical properties of hydrocarbon-bearing beds. There exist no quantitative interpretation methods to account for shoulder-bed effects on Σ logs acquired in sand-shale laminated reservoirs. Because of diffusion effects between dissimilar beds, Σ logs acquired in such formations do not obey mixing laws between the Σ responses of pure-sand and pure-shale end members of the sedimentary sequence. We have developed a new numerical method to simulate PNC rapidly and accurately logs. The method makes use of late-time, thermal-neutron flux sensitivity functions (FSFs) to describe the contribution of multilayer formations toward the measured capture cross section. It includes a correction procedure based on 1D neutron diffusion theory that adapts the transport-equation-derived, base-case FSF of a homogeneous formation to simulate the response of vertically heterogeneous formations. Benchmarking exercises indicate that our simulation method yields average differences smaller than two capture units within seconds of computer central processing unit time with respect to PNC logs simulated with rigorous Monte Carlo methods for a wide range of geometrical, petrophysical, and fluid properties.
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Lazim, Aymen Adil, and Hussain Sakban Dawood. "Comparison between Rafidhiya and Shuaiba Domes within the properties of Mishrif Formation in Zubair Field; the implication of structural Geology and petrophysical analyses." Journal of Petroleum Research and Studies 10, no. 3 (November 15, 2020): 86–101. http://dx.doi.org/10.52716/jprs.v10i3.331.
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The current study combined both concepts of structural geology and petrophysical to understand the structural feature of Mishrif Formation and its implication on the petrophysical characterization of the formation in Shuaiba and Rafidhiya Domes (or culminations) in Zubair Field. Shuaiba and Rafidhiya are adjacent domes and these domes belong to the same Field but the domes separated by saddle may related to Basra – Zubair basement fault.
The domes have different petrophysical properties of Mishrif Formation; consequently, influenced in water and oil saturation. Therefore, the study tries to understand the structural and petrophysical position of Mishrif Formation of the domes. The structural analysis included geometric and genetic analysis, whereas petrophysical analysis used open hole logs interpretation to determine the petrophysical characteristics (especially the distribution of porosity, permeability, and water saturation.
It was concluded that may a variation in porosity and permeability of Mishrif Formation for Shuaiba and Rafidhiya domes because each dome was formed by a different folding mechanism effected on the petrophysical properties. The structural geology analysis detects that may be Shuaiba dome formed by bending fold mechanism (vertical force of salt structure), while Rafidhiya dome by buckling fold mechanism (parallel force of collision of Arabian and Eurasian plate). These mechanisms may directly be affected in permeability distribution, and consequently on oil and water saturation of Mishrif Formation. Thus, Shuaiba Dome has thinning in hinge area and extensional force leads to create fractures and karst phenomena, and as a result, high permeability in upper Mishrif. On the contrary, Rafidhiya Dome has a thickening feature and there is no indication of karst phenomena and low permeability. Therefore, the Mishrif of Shuaiba dome permeable and oil-saturated, while, it flooded with water in Rafidhiya Dome. The disconnection in reservoir pressure confirmed by difference in initial reservoir pressure of Mishrif Formation of Shuaiba Dome and recent reservoir pressure of Mishrif Formation of Rafidhiya Dome
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Mezin, A. A., M. Y. Shumskayte, V. N. Glinskikh, N. A. Golikov, and E. S. Chernova. "Reservoir properties of drill cutting by the nuclear magnetic resonance relaxometry and dielectric spectroscopy data." Earth sciences and subsoil use 43, no. 3 (October 7, 2020): 364–74. http://dx.doi.org/10.21285/2686-9993-2020-43-3-364-374.
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The purpose of the study is to extend the use of nuclear magnetic resonance relaxometry and dielectric spectrometry methods. This is realized through a complex interpretation of the data by the above methods to timely provide additional petrophysical information about the drill cuttings pore space properties and structure. The relevance of the study is that the data on the drill cuttings obtained by the NMR method can be used as prior information in the logging data interpretation before a detailed petrophysical study of the core sample or in case of the core absence in the sampling interval. The objects of study are the drill cuttings samples from the fields of the West Siberian oil-and-gas province. The samples are saturated with different fluids, and their reservoir properties are determined by the nuclear magnetic resonance and dielectric spectrometry methods. As part of the experimental research, nuclear magnetic resonance investigations of the core samples of different discretization degrees have been carried out to determine the reservoir properties of the samples depending on the degree of their particle size reduction. It has been shown that the obtained results do not depend on the particle size of the measured sample and are consistent with the results of the standard petrophysical studies. The relationship between the porosity and the saturating fluid type has been established. Based on the data obtained by the dielectric spectroscopy method, the study has determined the value of the complex dielectric constant that shows how the degree of saturation changes depending on the fluid, and what happens in the pore space. The complex interpretation of the results obtained by the two methods provides additional information on the drill cuttings reservoir properties that can be used as a priori information on the formation properties.
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Al-Najm, Fahad M., Muwafaq F. Al-Shahwan, and Fawzi M. Al-Beyati. "Petrophysical Characteristics and Reservoir Modeling of Mishirf Formation at Noor Oil Field, South of Iraq." Journal of Petroleum Research and Studies 7, no. 1 (May 6, 2021): 210–35. http://dx.doi.org/10.52716/jprs.v7i1.177.
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Petrophysical properties of the Mishrif reservoir at Noor oil field have been done. Based on the interpretation of the open hole data from wells (No-1, 2, 3, 4, and 5) .Which have been calculated total porosity, effective and secondary porosity, water and hydrocarbon saturation (moveable and residual hydrocarbon) in invaded and uninvaded zones. Depends on the calculated of petrophysical properties, Mishrif Formation can be divided into eight reservoir units (RU-1 to 8), separated by eight caped rock units (barrier) (Bar-1 to Bar8). Three-dimensional reservoir model of oil saturation was constructed using the Petrel Software, (2009). Distribution of these petrophysical properties for each reservoir unit within the studied field has been done. The results showed that the best reservoir units are the second, fourth and first reservoir unit. It’s worth mentioned here that the heterogeneity of the thicknesses of these units and its individual direction. In addition, observed that the oil saturation increases towards the north of the field at the well (No-5) and the center of the field at the well (No-4).
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Bhattacharya, Shuvajit, and Sumit Verma. "Seismic attribute and petrophysics-assisted interpretation of the Nanushuk and Torok Formations on the North Slope, Alaska." Interpretation 8, no. 2 (May 1, 2020): SJ17—SJ34. http://dx.doi.org/10.1190/int-2019-0112.1.
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Exploration of the Brookian sandstone reservoirs in the Nanushuk and Torok Formations on the North Slope of Alaska is a hot topic and presents opportunities to the oil and gas community because of their shallow depth, vast extent, and scope of development. The consecutive hydrocarbon discoveries announced by Repsol-Armstrong, Caelus Energy, and ConocoPhillips in 2015, 2016, and 2017 have indicated the presence of the vast recoverable resources on the North Slope in the Nanushuk and Torok reservoirs. We have investigated the detailed geophysical and petrophysical characteristics of these reservoirs. Our goal is to detect dominant geologic features in these formations using a combination of seismic attributes at the regional scale and analyze critical petrophysical and rock physics properties to evaluate formation heterogeneities and identify the reservoir targets by integrating well log and core data at the well scale. The Nanushuk Formation is expressed as topset reflections, whereas the Torok and gamma-ray zone formations are expressed as foresets and bottomsets on the seismic reflection data. Using seismic attributes, we mapped the extent of different geomorphological features, including shelf edges, channels, slides, and basin-floor fans, all with significant amplitude anomalies. The shelf edges continue for tens to hundreds of miles along the north/northwest and east–west directions, depending on the areas. The internal characters of these formations delineated by conventional well logs and advanced petrophysical analysis reveal their vertical heterogeneities and complexities, in terms of reservoir properties. We conclude that the reservoirs are vertically and laterally heterogeneous. These are thin-bedded low-resistivity reservoirs. Only a few zones in the parasequences are oil-saturated. We find that a combination of low [Formula: see text] ratio and acoustic impedance can be a useful proxy to detect the hydrocarbon-bearing sand intervals in these formations.
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Korhonen, Juha, and Heikki Säävuori. "Regional interpretation of aerogeophysical and petrophysical data from the Peräpohja area, northern Finland." Geoexploration 23, no. 3 (September 1985): 440. http://dx.doi.org/10.1016/0016-7142(85)90049-3.
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Lenz, B., H. J. Mauritsch, and J. R. Reisinger. "Petrophysical investigations in the Southern Bohemian Massif (Austria): Data-acquisition, -organisation and-interpretation." Mineralogy and Petrology 58, no. 3-4 (1996): 279–300. http://dx.doi.org/10.1007/bf01172100.
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Toumelin, Emmanuel, Carlos Torres-Verdin, Boqin Sun, and Keh-Jim Dunn. "Limits of 2D NMR Interpretation Techniques to Quantify Pore Size, Wettability, and Fluid Type: A Numerical Sensitivity Study." SPE Journal 11, no. 03 (September 1, 2006): 354–63. http://dx.doi.org/10.2118/90539-pa.
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Summary Two-dimensional (2D) NMR techniques have been proposed as efficient methods to infer a variety of petrophysical parameters, including mixed fluid saturation, in-situ oil viscosity, wettability, and pore structure. However, no study has been presented to quantify the petrophysical limitations of such methods. We address this problem by introducing a pore-scale framework to accurately simulate suites of NMR measurements acquired in complex rock/fluid models. The general pore-scale framework considered in this paper is based on NMR random walks for multiphase fluid diffusion and relaxations, combined with Kovscek's pore-scale model for two-phase fluid saturation and wettability alteration. We use standard 2D NMR methods to interpret synthetic data sets for diverse petrophysical configurations, including two-phase saturations with different oil grades, mixed wettability, or carbonate pore heterogeneity. Results from our study indicate that for both water-wet and mixed-wet rocks, T2 (transverse relaxation)/D (diffusion) maps are reliable for fluid typing without the need for independently determined cutoffs. However, significant uncertainty exists in the estimation of fluid type, wettability, and pore structure with 2D NMR methods in cases of mixed-wettability states. Only light oil wettability can be reliably detected with 2D NMR interpretation methods. Diffusion coupling in carbonate rocks introduces additional problems that cannot be circumvented with current 2D NMR techniques. Introduction Wettability state and oil viscosity can play a significant role in the NMR response of saturated rocks. This property of NMR measurements has been discussed in recent papers (Freedman et al. 2003) for particular examples of rock systems. However, to date, no systematic study has been published of the reliability and accuracy of NMR methods to assess fluid viscosity and wettability, including cases of mixed wettability. This paper quantifies the sensitivity of 2D relaxation/diffusion NMR techniques to mixed wettability and fluid viscosity in generic rock models. Given that measurements are often made on rock samples with uncertain petrophysical properties and therefore uncertain corresponding measurement contributions, the work described in this paper is based on the numerical simulation of pore-scale systems. We introduce a general numerical model that simultaneously includes immiscible fluid viscosities, water or mixed wettability, variable fluid saturations and history, and disordered complexity of rock structure. Geometrical fluid distributions at the pore scale were considered a function of pore size, saturation history, and wettability following Kovscek et al.'s model of mixed-oil-wet rocks (1993). We simulated suites of NMR measurements with random walkers within these pore-scale geometries, and subsequently inverted into relaxation/diffusion NMR maps. The objective of this paper is to assess the accuracy of 2D NMR interpretation techniques to detect fluid and wettability types, and to quantify pore-size distributions. The first section of the paper summarizes the principles and limitations of current NMR petrophysical interpretation. We then summarize our pore-scale modeling procedure, its assumptions, and limitations. Subsequent sections analyze simulation results obtained for drainage and imbibition involving water-wettability and mixed-oil-wettability with partial saturations of water and different hydrocarbon types in a generic clay-free rock model. Next, we consider the case of coupled carbonate rocks with emphasis on the assessment of wettability and microporosity.
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Frooqnia, Amir, Carlos Torres-Verdín, Kamy Sepehrnoori, and Rohollah Abdhollah-Pour. "Transient Coupled Borehole/Formation Fluid-Flow Model for Interpretation of Oil/Water Production Logs." SPE Journal 22, no. 01 (July 21, 2016): 389–406. http://dx.doi.org/10.2118/183628-pa.
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Summary Interpretation of two-phase production logs (PLs) traditionally constructs borehole fluid-flow models decoupled from the physics of reservoir rocks. However, quantifying formation dynamic petrophysical properties from PLs requires simultaneous modeling of both borehole and formation fluid-flow phenomena. This paper develops a novel transient borehole/formation fluid-flow model that allows quantification of the effect of formation petrophysical properties on measurements acquired with production-logging tools (PLTs). We invoke a 1D, isothermal, two-fluid formulation to simulate borehole fluid-phase velocity, pressure, volume fraction, and density in oil/water-flow systems. The developed borehole fluid-flow model implements oil-dominant and water-dominant bubbly flow regimes with the inversion point taking place approximately when the oil volume fraction is equal to 0.5. Droplet diameter is dynamically modified to simulate interfacial drag effects, and to effectively account for variations of slip velocity in the borehole. Subsequently, a new successive iterative method interfaces the borehole and formation fluid-flow models by introducing appropriate source terms into the borehole fluid-phase mass-conservation equations. The novel iterative coupling method integrated with the developed borehole fluid-flow model allows dynamic modification of reservoir boundary conditions to accurately simulate transient behavior of borehole crossflow taking place across differentially depleted rock formations. In the case of rapid variations of near-borehole properties, frequent borehole/formation communication inevitably increases the computational time required for fluid-flow simulation. Despite this limitation, in a two-layer reservoir model penetrated by a vertical borehole, the coupling method accurately quantifies a 14% increase of volume-averaged oil-phase relative permeability of the low-pressure layer caused by through-the-borehole cross-communication of differentially depleted layers. Sensitivity analyses indicate that the alteration of near-borehole petrophysical properties primarily depends on formation average pressure, fluid-phase density contrast, and borehole-deviation angle. A practical application of the new coupled fluid-flow model is numerical simulation of borehole production measurements to estimate formation average pressure from two-phase selective-inflow-performance (SIP) analysis. This study suggests that incorporating static (shut-in) PL passes into the SIP analysis could result in misleading estimation of formation average pressure.
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Magoba, Moses, and Mimonitu Opuwari. "Petrophysical interpretation and fluid substitution modelling of the upper shallow marine sandstone reservoirs in the Bredasdorp Basin, offshore South Africa." Journal of Petroleum Exploration and Production Technology 10, no. 2 (November 7, 2019): 783–803. http://dx.doi.org/10.1007/s13202-019-00796-1.
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Abstract The fluid substitution method is used for predicting elastic properties of reservoir rocks and their dependence on pore fluid and porosity. This method makes it possible to predict changes in elastic response of a rock saturation with different fluids. This study focused on the Upper Shallow Marine sandstone reservoirs of five selected wells (MM1, MM2, MM3, MM4, and MM5) in the Bredasdorp Basin, offshore South Africa. The integration of petrophysics and rock physics (Gassmann fluid substitution) was applied to the upper shallow marine sandstone reservoirs for reservoir characterisation. The objective of the study was to calculate the volume of clay, porosity, water saturation, permeability, and hydrocarbon saturation, and the application of the Gassmann fluid substitution modelling to determine the effect of different pore fluids (brine, oil, and gas) on acoustic properties (compressional velocity, shear velocity, and density) using rock frame properties. The results showed average effective porosity ranging from 8.7% to 16.6%, indicating a fair to good reservoir quality. The average volume of clay, water saturation, and permeability values ranged from 8.6% to 22.3%, 18.9% to 41.6%, and 0.096–151.8 mD, respectively. The distribution of the petrophysical properties across the field was clearly defined with MM2 and MM3 revealing good porosity and MM1, MM4, and MM5 revealing fair porosity. Well MM4 revealed poor permeability, while MM3 revealed good permeability. The fluid substitution affected rock property significantly. The primary velocity, Vp, slightly decreased when brine was substituted with gas in wells MM1, MM2, MM3, and MM4. The shear velocity, Vs, remained unaffected in all the wells. This study demonstrated how integration of petrophysics and fluid substitution can help to understand the behaviour of rock properties in response to fluid saturation changes in the Bredasdorp Basin. The integration of these two disciplines increases the obtained results’ quality and reliability.