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1
Yogi, Ade. "Petrophysics Analysis for Reservoir Characterization of Cretaceous Clastic Rocks: A Case Study of the Arafura Basin." Jurnal Geologi dan Sumberdaya Mineral 21, no. 3 (August 28, 2020): 129. http://dx.doi.org/10.33332/jgsm.geologi.v21i3.527.
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This study presents petrophysics analysis results from two wells located in the Arafura Basin. The analysis carried out to evaluate the reservoir characterization and its relationship to the stratigraphic sequence based on log data from the Koba-1 and Barakan-1 Wells. The stratigraphy correlation section of two wells depicts that in the Cretaceous series a transgression-regression cycle. The petrophysical parameters to be calculated are the shale volume and porosity. The analysis shows that there is a relationship between stratigraphic sequences and petrophysical properties. In the study area, shale volumes used to make complete rock profiles in wells assisted by biostratigraphic data, cutting descriptions, and core descriptions. At the same time, porosity shows a conformity pattern with the transgression-regression cycle.Keywords: petrophysics, reservoir characterization, Cretaceous, transgressive-regressive cycle
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Giraud, Jérémie, Evren Pakyuz-Charrier, Mark Jessell, Mark Lindsay, Roland Martin, and Vitaliy Ogarko. "Uncertainty reduction through geologically conditioned petrophysical constraints in joint inversion." GEOPHYSICS 82, no. 6 (November 1, 2017): ID19—ID34. http://dx.doi.org/10.1190/geo2016-0615.1.
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We have developed a joint geophysical inversion workflow that aims to improve subsurface imaging and decrease uncertainty by integrating petrophysical constraints and geologic data. In this framework, probabilistic geologic modeling is used as a source of information to condition the petrophysical constraints spatially and to derive starting models. The workflow then uses petrophysical measurements to constrain the values retrieved by geophysical joint inversion. The different sources of constraints are integrated into a least-squares framework to capture and integrate information related to geophysical, petrophysical, and geologic data. This allows us to quantify the posterior state of knowledge and to calculate posterior statistical indicators. To test this workflow, using geologic field data, we have generated a set of geologic models, which we used to derive a probabilistic geologic model. In this synthetic case study, we found that the integration of geologic information and petrophysical constraints in geophysical joint inversion could reduce uncertainty and improve imaging. In particular, the use of petrophysical constraints retrieves sharper boundaries and better reproduces the statistics of the observed petrophysical measurements. The integration of probabilistic geologic modeling permits more accurate retrieval of model geometry, and it better constrains the solution while still satisfying the statistics derived from geologic data. The analysis of statistical indicators at each step of the workflow indicates that (1) the inversion methodology is effective when applied to complex geology and (2) the integration of prior information and constraints from geology and petrophysics significantly improves the inversion results while decreasing uncertainty. Finally, the analysis of uncertainty to the integration of the conditioned petrophysical constraints also indicates that, for this example, the best results are obtained for joint inversion using petrophysical constraints spatially conditioned by geologic modeling.
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Astic, Thibaut, Lindsey J. Heagy, and Douglas W. Oldenburg. "Petrophysically and geologically guided multi-physics inversion using a dynamic Gaussian mixture model." Geophysical Journal International 224, no. 1 (August 21, 2020): 40–68. http://dx.doi.org/10.1093/gji/ggaa378.
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SUMMARY In a previous paper, we introduced a framework for carrying out petrophysically and geologically guided geophysical inversions. In that framework, petrophysical and geological information is modelled with a Gaussian mixture model (GMM). In the inversion, the GMM serves as a prior for the geophysical model. The formulation and applications were confined to problems in which a single physical property model was sought, and a single geophysical data set was available. In this paper, we extend that framework to jointly invert multiple geophysical data sets that depend on multiple physical properties. The petrophysical and geological information is used to couple geophysical surveys that, otherwise, rely on independent physics. This requires advancements in two areas. First, an extension from a univariate to a multivariate analysis of the petrophysical data, and their inclusion within the inverse problem, is necessary. Secondly, we address the practical issues of simultaneously inverting data from multiple surveys and finding a solution that acceptably reproduces each one, along with the petrophysical and geological information. To illustrate the efficacy of our approach and the advantages of carrying out multi-physics inversions coupled with petrophysical and geological information, we invert synthetic gravity and magnetic data associated with a kimberlite deposit. The kimberlite pipe contains two distinct facies embedded in a host rock. Inverting the data sets individually, even with petrophysical information, leads to a binary geological model: background or undetermined kimberlite. A multi-physics inversion, with petrophysical information, differentiates between the two main kimberlite facies of the pipe. Through this example, we also highlight the capabilities of our framework to work with interpretive geological assumptions when minimal quantitative information is available. In those cases, the dynamic updates of the GMM allow us to perform multi-physics inversions by learning a petrophysical model.
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Chuanmao, Liang, and Gerald M. Friedman. "Petrophysical analysis of modern reef rocks." Carbonates and Evaporites 7, no. 1 (March 1992): 11–20. http://dx.doi.org/10.1007/bf03175389.
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J. Sunday, Abe, and Lurogho S. Ayoleyi. "Petrophysical analysis of “explorer” wells using well log and core data(a case study of “explorer” field, offshore Niger Delta, Nigeria)." International Journal of Advanced Geosciences 8, no. 2 (October 22, 2020): 219. http://dx.doi.org/10.14419/ijag.v8i2.31114.
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Reservoir characterization involves computing various petrophysical parameters and defining them in terms of their quantity and quality so as to ascertain the yield of the reservoir. Petrophysical well log and core data were integrated to analyze the reservoir characteristics of Explorer field, Offshore, Niger Delta using three wells. The study entails determination of the lithology, shale volume (Vsh), porosity (Φ), permeability (K), fluid saturation and cross plotting of petrophysical and core values at specific intervals to know their level of correlation. The analysis identified twelve hydrocarbon-bearing reservoir from three different wells. Average permeability value of the reservoir is 20, 0140md while porosity value range between 18% to 39%. Fluid type defined in the reservoirs on the basis of neutron/density log signature were basically water, oil and gas, low water saturation values ranging from 2.9% to 46% in Explorer wells indicate high hydrocarbon saturation. The Pearson Correlation Coefficient and Regression Equation gave a significant relationship between petrophysical derived data and core data. Scatter plot of petrophysical gamma ray values versus core gamma ray values gave an approximate linear relationship with correlation coefficient values of 0.6642, 0.9831 and 0.3261. Crossplot of petrophysical density values and core density values revealed that there is a strong linear relationship between the two data set with correlation coefficient values of 0.7581, 0.9872 and 0.3557, and the regression equation confirmed the relationship between the two data set. Also the scatter plot of petrophysical porosity density values versus core porosity density values revealed a strong linear relationship between the two data set with correlation coefficient values of 0.7608 and 0.9849, the regression equation confirmed this also. Crossplot of petrophysical porosity density values versus core porosity density values in Well 3 gave a very weak correlation coefficient values of 0.3261 and 0.3557 with a negative slope. The petrophysical properties of the reservoirs in Explorer Well showed that they contain hydrocarbon in commercial quantity and the cross plot of the petrophysical and core values showed direct relationship in most of the wells.
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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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Komatsu, Hideo. "Discussion of uncertainty relating to petrophysical analysis." Journal of the Japanese Association for Petroleum Technology 83, no. 1 (January 30, 2018): 34–39. http://dx.doi.org/10.3720/japt.83.34.
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Komatsu, Hideo. "Discussion of uncertainty relating to petrophysical analysis." Journal of the Japanese Association for Petroleum Technology 83, no. 1 (January 30, 2018): 34–39. http://dx.doi.org/10.3720/japt.83.34.
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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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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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Abdideh, Mohammad. "ESTIMATION OF THE FRACTURE DENSITY IN RESERVOIR ROCK USING REGRESSION ANALYSIS OF THE PETROPHYSICAL DATA." Geodesy and cartography 42, no. 3 (September 22, 2016): 85–91. http://dx.doi.org/10.3846/20296991.2016.1226384.
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Image logs are presently the main specialized tools for fracture detection in hydrocarbon reservoirs. Where image logs are not available, other less rewarding substitutes such as isolated well tests and type curve analysis, drilling mud loss history, core description and conventional petrophysical logs are used for fracture detection. In this paper a novel method is proposed for fracture density estimation in the fractured zones, using energy of petrophysical logs. Image and petrophysical logs from Asmari reservoir in one well of an oilfield in southwestern Iran were used to investigate the accuracy and applicability of the proposed method. Energy of the petrophysical logs in the fractured zones is calculated and linear and non-linear regressions between them are estimated. Results show that there is strong correlation between the energy of caliper, sonic (DT), density (RHOB) and lithology (PEF) logs with fracture density in well. In order to find a generalized estimator, a unique normalization method are developed, and by using it, a non-linear regression has been found which estimates fracture density with correlation coefficient of higher than 85%. The resultant regression has the capability of generalization in the studied field.
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Mitchell, J., T. C. Chandrasekera, D. J. Holland, L. F. Gladden, and E. J. Fordham. "Magnetic resonance imaging in laboratory petrophysical core analysis." Physics Reports 526, no. 3 (May 2013): 165–225. http://dx.doi.org/10.1016/j.physrep.2013.01.003.
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AlQuraishi, Abdulrahman A., Abdulaziz AlLaboun, Faisal AlGhamdi, and Saud AlHussinan. "Silurian qusaiba shale: Petrophysical, mineralogical and geochemical analysis." Journal of Petroleum Science and Engineering 192 (September 2020): 107209. http://dx.doi.org/10.1016/j.petrol.2020.107209.
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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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Pan, Jun Hui, Hui Wang, and Xiao Gang Yang. "Petrophysical Facies Classification Based on Fuzzy Inference Networks." Advanced Materials Research 634-638 (January 2013): 4017–21. http://dx.doi.org/10.4028/www.scientific.net/amr.634-638.4017.
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Aiming at the petrophysical facies recognition, a novel identification method based on the weighted fuzzy reasoning networks is proposed in the paper. First, the types and indicators are obtained from core analysis data and the results given by experts, and then the standard patterning database of reservoir petrophysical facies is established. Secondly, by integrating expert experiences and quantitative indicators to reflect the change of petrophysical facies, the classification model of petrophysical facies based on the weighted fuzzy reasoning networks is designed. The preferable application results are presented by processing the real data from the Sabei development zone of Daqing oilfield.
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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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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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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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Zhang, Bo, Tao Zhao, Xiaochun Jin, and Kurt J. Marfurt. "Brittleness evaluation of resource plays by integrating petrophysical and seismic data analysis." Interpretation 3, no. 2 (May 1, 2015): T81—T92. http://dx.doi.org/10.1190/int-2014-0144.1.
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The main considerations for well planning and hydraulic fracturing in unconventional resources plays include the amount of total organic carbon and how much hydrocarbon can be extracted. Brittleness is the direct measurement of a formation about the ability to create avenues for hydrocarbons when applying hydraulic fracturing. Brittleness can be directly estimated from laboratory stress-strain measurements, rock-elastic properties, and mineral content analysis using petrophysical analysis on well logs. However, the estimated brittleness using these methods only provides “cylinder” estimates near the borehole. We proposed a workflow to estimate brittleness of resource plays in 3D by integrating the petrophysics and seismic data analysis. The workflow began by brittleness evaluation using mineral well logs at the borehole location. Then, we used a proximal support vector machine algorithm to construct a classification pattern between rock-elastic properties and brittleness for the selected benchmark well. The pattern was validated using well-log data that were not used for constructing the classification. Next, we prestack inverted the fidelity preserved seismic gathers to generate a suite of rock-elastic properties volumes. Finally, we obtained a satisfactory brittleness index of target formations by applying the trained classification pattern to the inverted rock-elastic-property volumes.
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Katz, Simon, George Chilingar, Fred Aminzadeh, and Leonid Khilyuk. "Dissimilarity Analysis of Petrophysical Parameters as Gas-sand Predictors." Journal of Sustainable Energy Engineering 2, no. 2 (September 1, 2014): 101–15. http://dx.doi.org/10.7569/jsee.2014.629507.
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Fu, Jian, Xiao Min Tang, and Yu Chen Liu. "Analysis on Petrophysical Properties of the Shale Gas Reservoir." Advanced Materials Research 977 (June 2014): 208–12. http://dx.doi.org/10.4028/www.scientific.net/amr.977.208.
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As one of the most important means to obtain formation information, logging technology plays an important role in the identification and evaluation of shale gas reservoirs. This paper describs the formation mechanism and influential factors of shale gas reservoir storage characteristics from mineral composition and pore structure,etc. and discusses method for evaluating the TOC.
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Antal Lundin, Ildiko, and Mehrdad Bastani. "Analysis of petrophysical properties of some granitoids in Sweden." Journal of Applied Geophysics 62, no. 1 (May 2007): 74–87. http://dx.doi.org/10.1016/j.jappgeo.2006.09.002.
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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.
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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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Siddiqui, Shameem, Taha M. Okasha, James J. Funk, and Ahmad M. Al-Harbi. "Improvements in the Selection Criteria for the Representative Special Core Analysis Samples." SPE Reservoir Evaluation & Engineering 9, no. 06 (December 1, 2006): 647–53. http://dx.doi.org/10.2118/84302-pa.
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Summary The data generated from special-core-analysis (SCAL) tests have a significant impact on the development of reservoir engineering models. This paper describes some of the criteria and tests required for the selection of representative samples for use in SCAL tests. The proposed technique ensures that high-quality core plugs are chosen to represent appropriate flow compartments or facies within the reservoir. Visual inspection and, sometimes, computerized tomography (CT) images are the main tools used for assessing and selecting the core plugs for SCAL studies. Although it is possible to measure the brine permeability (kb), there is no direct method for determining the porosity (f) of SCAL plugs without compromising their wettability. Other selection methods involve using the conventional-core-analysis data (k and f) on "sister plugs" as a general indicator of the properties of the SCAL samples. A selective technique ideally suited for preserved or "native-state" samples has been developed to identify reservoir intervals with similar porosity/permeability relationships. It uses a combination of wireline log, gamma scan, quantitative CT, and preserved-state brine-permeability data. The technique uses these data to calculate appropriate depth-shifted reservoir-quality index (RQI) and flow-zone indicator (FZI) data, which are then used to select representative plug samples from each reservoir compartment. As an example application, approximately 400 SCAL plugs from an Upper Jurassic carbonate reservoir in the Middle East were tested using the selection criteria. This paper describes the step-by-step procedure to select representative plugs and criteria for combining the plugs for meaningful SCAL tests. Introduction The main goal of coring is to retrieve core samples from a well to get the maximum amount of information about the reservoir. Core samples collected provide important petrophysical, petrographic, paleontological, sedimentological, and diagenetic information. From a petrophysical point of view, the whole-core and plug samples typically undergo the following tests: CT scan, gamma scan, conventional tests, SCAL tests, rock mechanics, and other special tests. The data are combined to get information on heterogeneity, depth shift between core and log data, whole-core and plug porosity and permeability, porosity/permeability relationship, fluid content (Dean-Stark), RQI, FZI, wettability, relative permeability, capillary pressure, stress/strain relationship, and compressibility. The petrophysical data generated in this way play important roles in reservoir characterization and modeling, log calibration, reservoir simulation, and overall field production and development planning. Among all the petrophysical tests, the SCAL tests (which include wettability, capillary pressure, and relative permeability determination) are critical and time-consuming. A reservoir-condition relative permeability test can sometimes run for several months when mimicking the actual flow mechanisms taking place in the field. Therefore, it is very important to design these tests properly and, in particular, to select the samples that ensure meaningful results. In short, the samples must be "representative samples," which can capture the overall variability within the reservoir in a more scientific way. Unfortunately, the most important aspect of all SCAL procedures, the sample selection, is one of those least discussed. According to Corbett et al. (2001), API's RP40 (Recommended Practices for Core Analysis) makes very little reference to sampling; similarly, textbooks on petrophysics do not have sections on sampling. The Corbett et al. paper reviewed the statistical, petrophysical, and geological issues for sampling and proposed a series of considerations. This has led to the development of a method (Mohammed and Corbett 2002) using hydraulic units in a relatively simple clastic reservoir. In this paper, some issues related to sample-selection criteria (with special focus on carbonate reservoirs) will be discussed. A large data set of conventional, whole-core, and special-core analyses on a well in an Upper Jurassic carbonate reservoir was used to characterize representative samples for SCAL tests.
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Alkhayyat, Raniah S., Fadhil S. Kadhim, and Yousif khalaf Yousif. "The Use of Nuclear Magnetic Resonance (NMR) Measurements and Conventional Logs to Predict Permeability for a Complex Carbonate Formation." Journal of Petroleum Research and Studies 11, no. 3 (September 19, 2021): 82–98. http://dx.doi.org/10.52716/jprs.v11i3.534.
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Permeability is one of the most important property for reservoir characterization, and its prediction has been one of the fundamental challenges specially for a complex formation such as carbonate, due to this complexity, log analysis cannot be accurate enough if it’s not supported by core data, which is critically important for formation evaluation. In this paper, permeability is estimated by making both core and log analysis for five exploration wells of Yammama formation, Nasiriyah oil field. The available well logging recorders were interpreted using Interactive Petrophysics software (IP) which used to determine lithology, and the petrophysical properties. Nuclear Magnetic Resonance (NMR) Measurements is used for laboratory tests, which provide an accurate, porosity and permeability measurements. The results show that the main lithology in the reservoir is limestone, in which average permeability of the potential reservoir units’ values tend to range from 0.064275 in zone YA to 20.74 in zone YB3, and averaged porosity values tend to range from 0.059 in zone YA to 0.155 in zoneYB3. Zone YB3 is found to be the best zone in the Yammama formation according to its good petrophysical properties. The correlation of core-log for permeability and porosity produce an acceptable R^2 equal to 0.618, 0.585 respectively
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Kharitontseva, Polina, Andy Gardiner, Marina Tugarova, Dmitrii Chernov, Elizaveta Maksimova, Ilia Churochkin, and Valeriy Rukavishnikov. "An Integrated Approach for Formation Micro-Image Rock Typing Based on Petrography Data: A Case Study in Shallow Marine Carbonates." Geosciences 11, no. 6 (May 30, 2021): 235. http://dx.doi.org/10.3390/geosciences11060235.
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Core rock-typing (RT) is commonly used for creating geologically reliable models of porous media in carbonate reservoirs. This approach is more advanced than the traditional porosity–permeability relationship and is based on the division of carbonate rocks into groups, using common classifications (lithofacies, FZI, Winland–Pittman, etc.). These clustering methods can provide either geological or petrophysical descriptions of the identified rock types. Besides, the connection of identified core rock types with standard logs could be challenging due to the different scales of measurement. This paper considers the creation of a new approach, named “integrated rock-typing,” which connects geologically and petrophysically driven rock types using borehole image logs. The methodology was applied to an Upper Devonian–Lower Carboniferous carbonate field. The workflow comprises borehole image structural/textural analysis with vug fraction identification, quantitative geological descriptions from thin sections, and petrophysical measurements. The geological section is divided into six rock types, which were controlled by sedimentary and diagenetic processes. The created Rock Type Catalogue provides clear links between rock types and log data, including wells with standard suites of logs. The results will be useful for geological modelling and validation of the future drilling strategy for the studied field.
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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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Yeriomina, Natalia, Vladimir Gridin, Zinaida Sterlenko, Yelena Tumanova, and Katerina Chernenko. "Structure-texture peculiarities influence on petrophysical properties of Neftekumsk carbonate sediments." E3S Web of Conferences 164 (2020): 01007. http://dx.doi.org/10.1051/e3sconf/202016401007.
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The analysis of structure-texture peculiarities of carbonate sediments of Neftekumsk’ reservoir within the limits of Zimne-Stavkinsko- Pravoberezhny field was realized in the field of massive bioherm buildups and interreef lowerings in accordance with data of the core analyses. The existing pore space was divided into structure-texture classes. The correlations between petrofabrics and petrophysical parameters were determined. The received data can be used for describing of the three- dimensional distribution of petrophysical properties with the aim to increase the quality of three-dimensional (3-D) geological models.
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Haris, Abdul, Ressy Sandrina, and Agus Riyanto. "INTEGRATED AVO, ELASTIC SEISMIC INVERSION AND PETROPHYSICAL ANALYSIS FOR RESERVOIR CHARACTERIZATION: A CASE STUDY OF GAS FIELD, SOUTH SUMATERA BASIN." Spektra: Jurnal Fisika dan Aplikasinya 3, no. 1 (April 30, 2018): 7–14. http://dx.doi.org/10.21009/spektra.031.02.
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Integrated Amplitude Versus Offset ( AVO), elastic seismic inversion and petrophysical analysis have been successfully applied to estimate the elastic parameters of the reservoir for a case study of the gas field in south Sumatera basin. This paper aims to have better understanding the petrophysical properties of the reservoir. The petrophysical analysis was carried out by performing routine formation evaluation that includes calculation of shale volume, porosity, and water saturation of basic well log data. Sensitivity analysis was conducted to evaluate the sensitivity parameters of the log for changing in lithology, porosity, and fluid content in the reservoir. For completing the availability of elastic parameter from well log data, shear wave logs were derived from Castagna’s mudrock line relationship. Further, P-impedance, S-impedance, VpVs ratio, LambdaRho (λρ), MuRho (μρ) and density(ρ) were then calculated through a Lambda-Mu-Rho (LMR) transformation. Prior to performing AVO analysis and elastic seismic inversion, super gather technique was applied to improve the reliability of pre-stack seismic data. Elastic seismic inversion was carried out to extract the lateral elastic properties to capture lithology and fluid changes in the reservoir. In addition, AVO analysis of pre-stacked data was applied to identify hydrocarbon-bearing sandstone at target zone. The petrophysical analysis shows that porosity versus density crossplot is able to distinguish sand-shale based on 34% shale volume cutoff, while LMR crossplot is able to delineate hydrocarbon zone at water saturation value under 65%. The predicted lateral elastic parameter shows slightly higher value compare to overlying layer.
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Neff, Dennis B. "Estimated pay mapping using three‐dimensional seismic data and incremental pay thickness modeling." GEOPHYSICS 55, no. 5 (May 1990): 567–75. http://dx.doi.org/10.1190/1.1442868.
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Better estimates of hydrocarbon pay thickness and reservoir distribution are achieved if forward modeling is combined with crossplot cluster analysis before the seismic amplitude and isochron data are converted into estimates of pay thickness. To facilitate this process, an enhanced convolutional modeling technique that incorporates petrophysical data and equations into the synthetic seismogram generation process was developed. These incremental pay thickness (IPT) forward models provide the pertinent seismic and petrophysical values required for crossplot analysis. The crossplot analyses then define which seismic variables (trough amplitude, peak amplitude, time structure, isochron, etc.) are most uniquely related to a pay thickness parameter (gross thickness, net thickness, net porosity thickness, or hydrocarbons in place). Work to date, mostly in offshore Gulf Coast gas sands, has shown significant variation in the crossplot transforms required to convert seismic data to estimated pay maps. As such, an interactive, model‐based, interpretive approach is recommended as an appropriate means to integrate petrophysical, geologic, and 3-D seismic data in the creation of reservoir pay maps.
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Essien, Ubong, Akaninyene Akankpo, and Okechukwu Agbasi. "Evaluation of Reservoir’s Petrophysical Parameters, Niger Delta, Nigeria." International Journal of Advanced Geosciences 5, no. 1 (April 11, 2017): 19. http://dx.doi.org/10.14419/ijag.v5i1.7456.
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Petrophysical analysis was performed in two wells in the Niger Delta Region, Nigeria. This study is aimed at making available petrophysical data, basically water saturation calculation using cementation values of 2.0 for the reservoir formations of two wells in the Niger delta basin. A suite of geophysical open hole logs namely Gamma ray; Resistivity, Sonic, Caliper and Density were used to determine petrophysical parameters. The parameters determined are; volume of shale, porosity, water saturation, irreducible water saturation and bulk volume of water. The thickness of the reservoir varies between 127ft and 1620ft. Average porosity values vary between 0.061 and 0.600; generally decreasing with depth. The mean average computed values for the Petrophysical parameters for the reservoirs are: Bulk Volume of Water, 0.070 to 0.175; Apparent Water Resistivity, 0.239 to 7.969; Water Saturation, 0.229 to 0.749; Irreducible Water Saturation, 0.229 to 0.882 and Volume of Shale, 0.045 to 0.355. The findings will also enhance the proper characterization of the reservoir sands.
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Hassane, Amadou, Chukwuemeka Ngozi Ehirim, and Tamunonengiyeofori Dagogo. "Rock physics diagnostic of Eocene Sokor-1 reservoir in Termit subbasin, Niger." Journal of Petroleum Exploration and Production Technology 11, no. 9 (August 20, 2021): 3361–71. http://dx.doi.org/10.1007/s13202-021-01259-2.
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AbstractEocene Sokor-1 reservoir is intrinsically heterogeneous and characterized by low-contrast low-resistivity log responses in parts of the Termit subbasin. Discriminating lithology and fluid properties using petrophysics alone is complicated and undermines reservoir characterization. Petrophysics and rock physics were integrated through rock physics diagnostics (RPDs) modeling for detailed description of the reservoir microstructure and quality in the subbasin. Petrophysical evaluation shows that Sokor-1 sand_5 interval has good petrophysical properties across wells and prolific in hydrocarbons. RPD analysis revealed that this sand interval could be best described by the constant cement sand model in wells_2, _3, _5 and _9 and friable sand model in well_4. The matrix structure varied mostly from clean and well-sorted unconsolidated sands as well as consolidated and cemented sandstones to deteriorating and poorly sorted shaly sands and shales/mudstones. The rock physics template built based on the constant cement sand model for representative well_2 diagnosed hydrocarbon bearing sands with low Vp/Vs and medium-to-high impedance signatures. Brine shaly sands and shales/mudstones were diagnosed with moderate Vp/Vs and medium-to-high impedance and high Vp/Vs and medium impedance, respectively. These results reveal that hydrocarbon sands and brine shaly sands cannot be distinctively discriminated by the impedance property, since they exhibit similar impedance characteristics. However, hydrocarbon sands, brine shaly sands and shales/mudstones were completely discriminated by characteristic Vp/Vs property. These results demonstrate the robust application of rock physics diagnostic modeling in quantitative reservoir characterization and may be quite useful in undrilled locations in the subbasin and fields with similar geologic settings.
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Azeez, Hasan Saleh, Dr Abdul Aali Al-Dabaj, and Dr Samaher Lazim. "Petrophysical Analysis of an Iraqi Gas Field (Mansuriya Gas Field)." Journal of Engineering 26, no. 3 (March 1, 2020): 100–116. http://dx.doi.org/10.31026/j.eng.2020.03.09.
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Mansuriya Gas field is an elongated anticlinal structure aligned from NW to SE, about 25 km long and 5-6 km wide. Jeribe formation is considered the main reservoir where it contains condensate fluid and has a uniform thickness of about 60 m. The reservoir is significantly over-pressured, (TPOC, 2014).
This research is about well logs analysis, which involves the determination of Archie petrophysical parameters, water saturation, porosity, permeability and lithology. The interpretations and cross plots are done using Interactive Petrophysics (IP) V3.5 software.
The rock parameters (a, m and n) values are important in determining the water saturation where (m) can be calculated by plotting the porosity from core and the formation factor from core on logarithmic scale for both and the slope which represent (m) then Pickett plot method is used to determine the other parameters after calculating Rw from water analysis .
The Matrix Identification (MID), M-N and Density-Neutron crossplots indicates that the lithology of Jeribe Formation consists of dolomite, limestone with some anhydrite also gas-trend is clear in the Jeribe Formation.
The main reservoir, Jeribe Formation carbonate, is subdivided into 8 zones namely J1 to J8, based mainly on porosity log (RHOB and NPHI) trend, DT trend and saturation trend.
Jeribe formation was considered to be clean in terms of shale content .The higher gamma ray because of the uranium component which is often associated with dolomitisationl and when it is removed and only comprises the thorium and potassium-40 contributions, showed the gamma response to be low compared to the total gamma ray response that also contains the uranium contribution.While the Jeribe formation is considered to be clean in terms of shale content so the total porosity is equal to the effective porosity.No porosity cut off is found if cutoff permeability 0.01 md is applied while the porosity cut off approximately equal to 0.1 only for unit J6 & J8 if cutoff permeability 0.1 md is applied .
It can be concluded that no saturation cutoff for the units of Jeribe formation is found after a cross plot between water saturation and log porosity for the reservoir units of Jeribe formation and applied the calculated cut off porosity.
The permeability has been predicted using two methods: FZI and Classical, the two methods yield approximately the same results for all wells.
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Cerepi, Adrian, Louis Humbert, and René Burlot. "Petrophysical properties of porous medium from Petrographic Image Analysis data." Colloids and Surfaces A: Physicochemical and Engineering Aspects 187-188 (August 2001): 233–56. http://dx.doi.org/10.1016/s0927-7757(01)00636-7.
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Ruszkowski, Mr Peter. "An analysis of the Broken Hill exploration initiative petrophysical database." Exploration Geophysics 29, no. 3-4 (September 1998): 592–96. http://dx.doi.org/10.1071/eg998592.
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Wang, Haitao. "Improved dual-porosity models for petrophysical analysis of vuggy reservoirs." Journal of Geophysics and Engineering 14, no. 4 (May 23, 2017): 758–68. http://dx.doi.org/10.1088/1742-2140/aa6989.
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Tawfeeq, Yahya. "DIGITAL ROCK ANALYSIS: AN ALTERNATIVE METHOD TO PREDICT PETROPHYSICAL PROPERTIES, CASE STUDY FROM MISHRIF FORMATION." Iraqi Geological Journal 53, no. 2C (September 30, 2020): 34–55. http://dx.doi.org/10.46717/igj.53.2c.4rs-2020-09-04.
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The digital core analysis of petrophysical properties replace the use of conventional core analysis by reducing the required time for investigation. Also, the ability to capture pore geometries and fluid behavior at the pore-scale improves the understanding of complex reservoir structures. In this work, 53 samples of 2D thin section petrographic images were used for analyses from the core plugs taken from the Buzurgan oil field. Each sample was impregnated with blue-dyed epoxy, thin sectioned and then was stained for discrimination of carbonate minerals. Each thin section has been described in detail and illustrated by photomicrographs. The studied samples include a variety of rock types. Packstone is the most common rock type observed followed by grainstone and packstone – wackestone. Floatstone and dolostone are noted rarely in the studied interval. However, the samples of thin section images are processed and digitized, utilizing MATLAB programming and image analysis software. The entire workflow of digital core analysis from image segmentation to petrophysical rock properties determination was performed. A focused has been made on determining effective and total porosity, absolute permeability, and irreducible water saturation. Absolute permeability is estimated with the Kozeny-Carman permeability correlation model and Timur-Coates permeability correlation model. Irreducible water saturation simply is derived from total and effective porosity. Also, some pore void characteristics, such as area and perimeter, were calculated. The results of Digital 2D image analysis have been compared to laboratory core measurements to investigate the reliability and restrictions of the digital image interpretation techniques.
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Cong, Lin, Yang Liu, Jing Chao Lei, Wen Long Li, and Hao Qing Sun. "An Analysis of Petrophysical Property Cutoff Properties of Tight Reservoir and its Influences Factors in West Liaohe Depression Yuanyanggou Area." Advanced Materials Research 868 (December 2013): 547–50. http://dx.doi.org/10.4028/www.scientific.net/amr.868.547.
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Petrophysical property cutoff effective reservoir properties can be affected by reservoir properties, crude property, depth, formation temperature, formation pressure and other factors, among which reservoir properties, burial depth and formation temperature are the main factors in effective reservoir development degree of deep tight sandstone, formation pressure has a great impact on the effective reservoir development, while fluid properties have a relatively small impact. The development of oil production technology would reduce petrophysical property cutoff, which will lead to the transformation of non-effective reservoir earlier reckoned into effective reservoir in the future. Therefore, it is necessary in oil and gas exploration to continuously analyze lower limit of effective reservoir physical properties.
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Oyno, Lars, B. G. Tjetland, K. H. Esbensen, Rune Solberg, Aase Scheie, and Tore Larsen. "Prediction of Petrophysical Parameters Based on Digital Video Core Images." SPE Reservoir Evaluation & Engineering 1, no. 01 (February 1, 1998): 82–87. http://dx.doi.org/10.2118/36853-pa.
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Summary Core-slab photography is a common way to document geological information from cores. Past practice has been to photograph core slabs with ordinary cameras that produce paper photographs. The presented method retrieves petrophysical properties from high-resolution digital video core images. The procedures described in this work are based on video images (standard RIO/B camera) of cores taken with a digital recording system. The system is able to record in both visible and UV light at different illumination angles, store images, compress/decompress images, and display one or several images as a continuous long core. The seamless core image is marked with depth scale and can be scrolled, scaled, and zoomed. Facilities for correlation with other related data, such as wireline logs, discrete core data, and microscopy images, are also included in the system. We used homogenous dry core plugs from three North Sea oil fields in this work. We recorded images of plug surface, together with conventional core-analysis data (i.e., porosity, gas permeability, average grain size, and mineralogy). The new method is based on processed digital images: light/shadow patterns are obtained by use of asymmetric, low-angle illumination in the green channel. Texture spectra of the rock material are obtained by dedicated image-analytical processing of these gray-scale images and by detecting textural features by use of a unique set of specially designed texture filters. We then calibrate these spectra with respect to measured petrophysical parameters by use of multivariate calibration [partial least squares (PLS)-regression]. Multivariate calibration is based on a set of representative training images, selected to span representative ranges of the intensive petrophysical parameters being modeled. On the basis of this calibration model, similar gray-level video images from new, unknown core sections (with geologically similar facies) are used to estimate properties of the core material by PLS-prediction. In this study it has been possible to model porosity, gas permeability, and average grain size (ORZ) of different formations with a relatively high accuracy and precision. PLS-modeling/-prediction is a strict empirical calibration procedure. The present method is critically dependent upon a thorough, geologically well-documented training data set. Results show that the method is capable of predicting a continuous log of these three petrophysical parameters based on core images calibrated against a set of routine laboratory core-analysis data taken at discrete intervals for a particular formation. The advantages of the new method are rapid and cost-efficient methods for prediction of petrophysical parameters, particularly from slim cores, and improved integration of geological records with wireline data. The method is proposed to be included in future routine laboratory core analysis studies because of its low cost and ability to predict values continuously along the core. Introduction In many cases where core material is available from a potential hydrocarbon reservoir, it is possible to perform conventional laboratory core analysis on selected zones or at regular intervals. These measurements are commonly used as input in numerical simulations predicting recovery from the field. The results are also commonly used for net pay calculations to provide a reserves estimate.1–4 Usually, conventional core plugs are taken at regular intervals (every 30 cm or every meter) in the reservoir zone. Core-analysis plugs are often neglected below the oil/water contact (OWC), sometimes also in other parts of the reservoir for various reasons. Core photography has been used for decades to document the geology in the reservoir for later study. The photographs are usually printed on paper with a few core lengths in each photograph. Obtaining a complete picture of the reservoir geology and petrophysics from the core photographs involves extensive leafing through numerous pages of core photographs. Also, paper photographs do not offer the possibility to perform image analysis. Advances in digital storage and image analysis, together with decreasing costs of computers, have now allowed the use of digital storage of core information.5–8 The work described in this article makes exclusive use of digitally recorded imagery. Core images are taken continuously along the slabbed core. Software automatically combines the core images into a seamless, continuous core image of the complete length of the core's interval. This opens the door to easy access to image analysis. In contrast with the routine core-analysis measurements, the present digital video images provide continuous information regarding the texture of the core material. If these images also could be used to extract petrophysical information, they could offer parameter values continuously along the entire cored material. Because reservoir material differs widely from field to field and also between wells, we expected some initial experimentation with optimal recording parameters as well as the geological calibration base to be necessary to tune a new type of image correlation model. Consider an image of core material, say sandstone, where each grain can be seen at an appropriate resolution; it is not difficult to accept that image analysis should be able to extract grain-size (and grain-size distribution) information pertaining to the material in the field of view. Grains can be seen down almost throughout the fine range of the sandstone grain size. Moreover, when applying different data analytical techniques to postprocess, earlier-derived texture spectra, it became clear that even other petrophysical parameters like porosity and permeability could indeed also be predicted. Multivariate calibration,18,19 to be explained further later, is carried out from a number of calibration samples where the desired petrophysical parameters are known (from traditional methods). The camera field of view was maintained constant, and an analysis area large enough to be representative for all types of material in the present study was determined by initial sensitivity analysis. The advantage of the presented method is that petrophysical parameters now can be predicted directly from identical video imagery on samples which then, of course, need not be measured in the laboratory. This approach can even be augmented so as also to produce results from layered zones, where routine core-analysis results are difficult to obtain. It can also provide results where routine core-analysis results are doubtful, for example, in unconsolidated cores. Last, it provides continuous petrophysical estimates from a core at a detail and at significantly lowered cost, which is both impractical and uneconomical to achieve with conventional core analysis.
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Pang, Ling Yun. "The Application of Reservoir Geo-Modeling Technology in Section07, Ticleni Oilfield." Applied Mechanics and Materials 580-583 (July 2014): 866–69. http://dx.doi.org/10.4028/www.scientific.net/amm.580-583.866.
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In the study of reservoir geo-modeling in Ticleni oilfield, structural model, the spatial framework of the geo-model was firstly constructed based on seismic and petrophysical data and integrated geological background analysis. Then the variogram function was analyzed based on petrophysical data and sedimentary setting analysis, and the litholofacies model was established. Finally, the property models were constructed with reservoir physical property controlled by lithofacies model. Therefore, the quantification of geological study achievements and the distribution of reservoir physical property are effectively combined, which provides the foundation for the sequent reservoir development of Section07.
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S S, Paul, Okwueze ., E. E, and Udo K I. "Petrophysical Analysis of Well Logs for the Estimation of Oil Reserves in Southern Niger Delta." International Journal of Advanced Geosciences 6, no. 1 (June 12, 2018): 145. http://dx.doi.org/10.14419/ijag.v6i1.11815.
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Gamma Ray log, Resistivity log, Density log, Micro-spherical focus log (MSFL), Deep Induction log (ILD) , Medium Induction log(ILM) and Spontaneous Potential (SP) log were collected for 2 wells in onshore Niger Delta. These insitu well logs were analyzed and interpreted. Porosity, permeability, water saturation, reservoir thickness and Shale volume were estimated for each hydrocarbon bearing zone delineated for each well. The parameters obtained were further analyzed and interpreted quantitatively to estimate the hydrocarbon potentials of each well. Twelve reservoir zones of interest (sand bodies) were delineated, correlated across the field and were ranked using average results of petrophysical parameters. In well one, Reservoirs E and F were identified as the thickest with 41ft each while reservoir A is the smallest in thickness (30ft). Petrophysical properties of hydrocarbon bearing zones delineated in well one ranged from 17.81% to 23.20% for porosity, 1292.09mD to 2018.17mD for permeability and 56.40% to 68.40% for hydrocarbon saturation compared to well 2 with 14.67% to 19.52% for porosity, 1211.61mD to1843.11mD for permeability and 51.80% to 66.40% for hydrocarbon saturation. The estimated averages of petrophysical properties for well one are 20.14% porosity, 1643.65mD permeability, 63.20% hydrocarbon saturation compared to well 2 with 15.55% porosity, 1582.58mD permeability and 61.93% hydrocarbon saturation. Results show 148.45MMBB and 145.91MMBB as oil reserve (Recoverable) for the field. From the results obtained, well one is likely to be more productive than well [2] and the field has exploitable oil in place.
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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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Shar, Abdul Majeed, Aftab Ahmed Mahesar, Ghazanfer Raza Abbasi, Asad Ali Narejo, and Asghar Ali Alias Daahar Hakro. "Influence of diagenetic features on petrophysical properties of fine-grained rocks of Oligocene strata in the Lower Indus Basin, Pakistan." Open Geosciences 13, no. 1 (January 1, 2021): 517–31. http://dx.doi.org/10.1515/geo-2020-0250.
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Abstract Nari Formation is considered as one of the most important oil and gas exploration targets. These fine-grained tight sandstone reservoirs face enormous challenges due to their extremely low matrix porosity and permeability. Hence, in this regard, the study was carried out to collect the high-quality data on petrophysical properties along with mineralogy and microstructural characteristics and diagenesis. The experiments performed includes the petrographic study and scanning electron microscopy, and X-ray diffraction analyses. Besides, the measurement of petrophysical properties was carried out to assess the likely influence of the reservoir quality. The petrographic analysis shows predominantly fine- to medium-grained grey samples along with calcite, clay, lithic fragments and iron oxides. Further, the thin-section observations revealed that the quartz is a principal mineral component in all the analysed samples ranging from 52.2 to 92.9%. The bulk volume of clay minerals that range from 5.3 to 16.1% of. The porosity and permeability measured range from 5.08 to 18.56% (average 7.22%) and from 0.0152 to 377 mD (average 0.25 mD), respectively. The main diagenetic processes that affected the sandstones of Nari Formation are mechanical compaction, grain deformation, cementation and quartz dissolution and have played a significant role in influencing the quality of the reservoir rock. Overall, it appears that the primary petrophysical properties (porosity and permeability) were decreased due to the mechanical compaction, lithification, cementation, and framework grain dissolution. Based on the integrated mineralogical, microstructural analysis, and the laboratory-based petrophysical properties, the samples exhibited poor porosity, permeability, and moderate clay content, which indicate that the Nari Formation is a poor quality reservoir.
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Kehinde, D. Oyeyemi, and P. Aizebeokhai Ahzegbobor. "Hydrocarbon trapping mechanism and petrophysical analysis of Afam field, offshore Nigeria." International Journal of Physical Sciences 10, no. 7 (April 16, 2015): 222–38. http://dx.doi.org/10.5897/ijps2015.4275.
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Ramamoorthy, Raghu, Charles Flaum, and Carolina Coll. "Geologically Consistent Resolution Enhancement of Petrophysical Analysis With Image Log Data." SPE Formation Evaluation 12, no. 02 (June 1, 1997): 95–100. http://dx.doi.org/10.2118/30607-pa.
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Eissa, Mohamed A., John Pfeiffer, and Heiman Alfredo Paz Ortega. "Seismic petrophysical analysis for thin sandstone reservoirs in Colombia's Guajira Basin." Leading Edge 28, no. 6 (June 2009): 640–47. http://dx.doi.org/10.1190/1.3148402.
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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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Hassan, Ahmed M., Walid M. Mabrouk, and Khamis M. Farhoud. "Petrophysical analysis for Ammonite-1 well, Farafra Area, Western Desert, Egypt." Arabian Journal of Geosciences 7, no. 12 (October 6, 2013): 5107–25. http://dx.doi.org/10.1007/s12517-013-1123-y.
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Hajto, Marek, Anna Przelaskowska, Grzegorz Machowski, Katarzyna Drabik, and Gabriel Ząbek. "Indirect Methods for Validating Shallow Geothermal Potential Using Advanced Laboratory Measurements from a Regional to Local Scale—A Case Study from Poland." Energies 13, no. 20 (October 21, 2020): 5515. http://dx.doi.org/10.3390/en13205515.
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This paper presents a broad overview of laboratory methods for measuring thermal properties and petrophysical parameters of carbonate rocks, and analytical methods for interpreting the obtained data. The investigation was conducted on carbonate rock samples from the Kraków region of Poland in the context of shallow geothermal potential assessment. The measurement techniques used included standard macroscopic examinations; petrophysical investigations (porosity, density); analysis of mineral composition thermal conductivity (TC) and specific heat measurements; and advanced investigations with the use of computed tomography (CT). Various mathematical models, such as layer model, geometric mean, and spherical and non-spherical inclusion models, were applied to calculate thermal conductivity based on mineralogy and porosity. The aim of this paper was to indicate the optimal set of laboratory measurements of carbonate rock samples ensuring sufficient characterization of petrophysical and thermal rock properties. This concerns both the parameters directly characterizing the geothermal potential (thermal conductivity) and other petrophysical parameters, e.g., porosity and mineral composition. Determining the quantitative relationship between these parameters can be of key importance in the case of a shortage of archival thermal conductivity data, which, unlike other petrophysical measurements, are not commonly collected. The results clearly show that the best correlations between calculated and measured TC values exist for the subgroup of samples of porosity higher than 4%. TC evaluation based on porosity and mineral composition correlation models gives satisfactory results compared with direct TC measurements. The methods and results can be used to update the existing 3D parametric models and geothermal potential maps, and for the preliminary assessment of geothermal potential in the surrounding area.
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Bray, Matthew, Jacquelyn Daves, Daniel Brugioni, Asm Kamruzzaman, Tom Bratton, Sheila Harryandi, Alena Grechishnikova, Ali Tura, Tom Davis, and Jim Simmons. "Multidisciplinary analysis of hydraulic stimulation and production effects within the Niobrara and Codell reservoirs, Wattenberg Field, Colorado — Part 1: Baseline reservoir conditions." Interpretation 9, no. 4 (July 12, 2021): SG1—SG12. http://dx.doi.org/10.1190/int-2020-0144.1.
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In the Wattenberg Field, the Reservoir Characterization Project at the Colorado School of Mines and Occidental Petroleum Corporation (Oxy) (formerly the Anadarko Petroleum Corporation) collected time-lapse seismic data for characterization of changes in the reservoir caused by hydraulic fracturing and production in the Niobrara Formation and Codell Sandstone member of the Carlile Formation. We have acquired three multicomponent seismic surveys to understand the dynamic reservoir changes caused by hydraulic fracturing and production of 11 horizontal wells within a 1 mi2 section (the Wishbone Section). The time-lapse seismic survey acquisition occurred immediately after the wells were drilled, another survey after stimulation, and a third survey after two years of production. In addition, we integrate core, petrophysical properties, fault and fracture characteristics, as well as P-wave seismic data to illustrate reservoir properties prior to simulation and production. Core analysis indicates extensive amounts of bioturbation in zones of high total organic content (TOC). Petrophysical analysis of logs and core samples indicates that chalk intervals have high amounts of TOC (>2%) and the lowest amount of clay in the reservoir interval. Core petrophysical characterization included X-ray diffraction analysis, mercury intrusion capillary pressure, N2 gas adsorption, and field emission scanning electron microscopy. Reservoir fractures follow four regional orientations, and chalk facies contain higher fracture density than marl facies. Integration of these data assist in enhanced well targeting and reservoir simulation.