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In the current work, wire line logs, core measurement data, and 3D seismic analysis are interpreted to evaluate the Nubian sandstone reservoir in the Saqqara oil field, Gulf of Suez. The petrophysical parameters of the studied reservoir, such as porosity, shale volume, water saturation, and net-pay thicknesses, are calculated from logs and integrated with that measured from core plugs to build a suitable model for the reservoir. This is done in addition to interpreting twenty 3D seismic lines to create a reasonable structure configuration for the study area. Prospect appraisal, reservoir management, and development benefit greatly from the thorough integration of all wire line log and core findings and seismic line interpretation. The structure is essential to the pattern of sedimentation and trapping in this location, based on the seismic interpretation of the examined area. The Nubian sandstone reservoir has favorable characteristics, according to the study’s findings: its net pay thickness reaches 496 feet, its porosity values are (10–16%), its water saturation are (12–53%), and its shale volume does not surpass 8%. The well-informed results of the comparative petrophysical study show that the examined Nubian sandstone reservoir is of excellent quality, as shown by the good relation coefficients between core porosity and permeability, which are equivalent to r = 0.79 and r = 0.81, respectively. Conversely, the developed model highlighting the necessary corrections for the appropriate model of the investigated reservoir highlights the differences between the core porosity and permeability values and the one derived from the log computation.Plain Language Summary: At Gulf of Suez’s Saqqara oil field, the Nubian sandstone reservoir is assessed by the interpretation of wire line logs, core measurement data, and three-dimensional seismic analysis. To create an appropriate model for the reservoir, the petrophysical parameters of the examined reservoir, such as porosity, shale volume, water saturation, and net-pay thicknesses, are computed from logs and combined with data obtained from core plugs. Twenty 3D seismic lines are interpreted in addition to this in order to construct a plausible structure configuration for the study area. A comprehensive integration of all wire line log and core data and seismic line interpretation is beneficial for prospect appraisal, reservoir management, and development. Seismic interpretation of the studied area indicates that the structure is critical to the pattern of sedimentation and trapping in this site. The Nubian sandstone reservoir under investigation is of outstanding quality, as indicated by the well-informed results of the comparative petrophysical analysis and the good relationship coefficients between core porosity and permeability, respectively. The disparities between the core porosity and permeability values and the one obtained from the log calculation are highlighted in the generated model that indicates the essential modifications for the proper model of the examined reservoir. [ABSTRACT FROM AUTHOR]

Increasing hydrocarbon production in Ukraine requires the development and introduction of new promising methodological and technological means of petrophysical support and drilling support for exploration areas based on modern scientific and technological achievements. The analysis of the geological structure of lithological and stratigraphic strata of the Neogene Krukenytska system of the Bilche-Volytska depression of the Precarpathian trough confirmed that each individual case has its own peculiarities both in the structure of the rock matrix and in the conditions of its formation. Based on the results of the analysis and evaluation of the quality of interpretation of physical parameters of geophysical surveys of complexly structured reservoir rocks of Neogene sediments, the influence of clay content, temperature and reservoir pressure on the readings of electrical, radioactive and acoustic measurements of mineralogical composition was established. Electrometric methods, which are part of a typical GDS complex, have their limitations when recording resistivity values, in particular, insufficient resolution and ambiguity in assessing the nature of saturation when studying complex reservoir rocks. In the process of assessing the nature of saturation of complexly constructed reservoir rocks of Neogene sediments, the presence of water-saturated rocks in the roof of gas-saturated formations without a continuous lintel was revealed, which also causes watering of productive horizons, thus reducing gas and condensate production. The sandy rocks of the Lower Dashava subsurface are characterized, in addition to normal interbedding, by the presence of hydrocarbon accumulations in lens-shaped traps with various petrophysical parameters. The established features of the geological structure of Neogene lithologic and stratigraphic strata confirm the complex geology of Neogene and Paleogene rocks and cause complications in geological and geophysical studies in exploration wells.

Petrographic and petrophysical characterizations of the pre-salt Chela formation of the Nsiamfumu and Liawenda fields in the onshore Coastal Basin of the D.R. Congo it was performed. These characterizations, as part of the static modelling of the reservoirs, involved reading log measurements, thin-slice observations of rock samples taken from this formation, calculations and interpretation of logs, CPI (Computer Processed Interpretation) and DST (Drill Stem Testing) from well tests. The following observations were obtained: • Wells Lw-1: the formation is characterized by dolomitic limestone and micaceous black shale with a thickness of 34 m having heavy oil indices and an average porosity of 17% and a salinity greater than 300 gr/L; • Well Lw-2: the formation is characterized by islands of sand, coarse sandstone and a few quartz pebbles with a thickness of 10m showing evidence of light oil, gas and an average porosity of 24%; • Shaft Lw-3: the formation is dominated by micaceous shale and dolomite interbeds with a thickness of 14m showing little evidence of hydrocarbons, only salt water and residual oils; • Puits Ns-1: the formation is characterized by beige to grey dolomite, grey shale and white sand with a thickness of 6m showing evidence of light oil and an average porosity of 20%. [ABSTRACT FROM AUTHOR]

Increasing hydrocarbon production in Ukraine requires the development and introduction of new promising methodological and technological means of petrophysical support and drilling support for exploration areas based on modern scientific and technological achievements. The analysis of the geological structure of lithological and stratigraphic strata of the Neogene Krukenytska system of the Bilche-Volytska depression of the Precarpathian trough confirmed that each individual case has its own peculiarities both in the structure of the rock matrix and in the conditions of its formation. Based on the results of the analysis and evaluation of the quality of interpretation of physical parameters of geophysical surveys of complexly structured reservoir rocks of Neogene sediments, the influence of clay content, temperature and reservoir pressure on the readings of electrical, radioactive and acoustic measurements of mineralogical composition was established. Electrometric methods, which are part of a typical GDS complex, have their limitations when recording resistivity values, in particular, insufficient resolution and ambiguity in assessing the nature of saturation when studying complex reservoir rocks. In the process of assessing the nature of saturation of complexly constructed reservoir rocks of Neogene sediments, the presence of water-saturated rocks in the roof of gas-saturated formations without a continuous lintel was revealed, which also causes watering of productive horizons, thus reducing gas and condensate production. The sandy rocks of the Lower Dashava subsurface are characterized, in addition to normal interbedding, by the presence of hydrocarbon accumulations in lens-shaped traps with various petrophysical parameters. The established features of the geological structure of Neogene lithologic and stratigraphic strata confirm the complex geology of Neogene and Paleogene rocks and cause complications in geological and geophysical studies in exploration wells. [ABSTRACT FROM AUTHOR]

Tight gas, a category of unconventional natural gas, relies on advanced intelligent monitoring methods for their extraction. Conventional logging for reservoir evaluation relies on logging data and the manual setting of evaluation criteria to classify reservoirs. However, the complexity and heterogeneity of tight reservoirs pose challenges in accurately identifying target layers by using traditional well-logging techniques. Machine learning may hold the key to solving this problem, as it enables computers to learn without being explicitly programmed and manually adding rules. Therefore, it is possible to make reservoir evaluations using machine learning methods. In this paper, the reservoir quality index (RQI) and porous geometric parameters obtained from the optimized inversion of the spherical–tubular model are adopted to evaluate the reservoir. Then, three different machine learning approaches, the random forest (RF) algorithm, support vector machine (SVM) algorithm, and extreme gradient boosting (XGB) algorithm, are utilized for reservoir classification. The selected dataset covers more than 7000 samples from five wells. The data from four wells are arranged as the training dataset, and the data of the remaining one well is designed as the testing dataset to calculate the prediction accuracies of different machine learning algorithms. Among them, accuracies of RF, SVM, and XGB are all higher than 90%, and XGB owns the highest result by reaching 97%. Machine learning based approaches can greatly assist reservoir prediction by implementing the well-logging data. The research highlights the application of reservoir classification with a higher prediction accuracy by combining machine learning algorithms with NMR-logging-based pore structure characterization, which can provide a guideline for sweet spot identification within the tight formation. This not only optimizes resource extraction but also aligns with the global shift towards clean and renewable energy sources, promoting sustainability and reducing the carbon footprint associated with conventional energy production. In summary, the fusion of machine learning and NMR-logging-based reservoir evaluation plays a crucial role in advancing both energy efficiency and the transition to cleaner energy sources. [ABSTRACT FROM AUTHOR]

This study is intended to interpret of well logs for the purpose of determining petrophysical parameters for Mishrif formation in the Amarah Oil Field. This field is situated in the province of Mysan ten kilometers to the southwest of Amarah and ten kilometers to the northwest of Halafaya's field, and is located southeast of the field of Kamit and about 30 km. M–N cross plot as well as the Matrix Identification (MID) have been applied to calculate mineralogy and lithology of the formation using well logs, cross plots, and reservoir quality index (RQI) along with flow zone indicator (FZI) outputs. The findings indicated that dolomite is just slightly present in the formation, which is primarily composed of calcite. The lithology determination using density–neutron cross plot shows that the formation is primarily limestone with some shale. The interpretation revealed that non-reservoir (barrier) beds divide the seven reservoir units that make up the majority of the Mishrif Formation. The parameters of Archi's model were calculated using Pickett's plot. The range values for Archie's parameters, namely a, m, and n, were found to be 1, 1.29, and 2, respectively. [ABSTRACT FROM AUTHOR]

Tectonically deformed coal (TDC) is closely related to gas outbursts. Since TDC exploration is an essential objective for coalfield exploration, it is of great significance to study the petrophysical properties of TDCs and explore their differences. This study collected 17 TDCs and undeformed coal samples from the Huaibei coalfield and ultrasonically tested their petrophysical parameters, including densities, P- and S-wave velocities, and their derived petrophysical parameters (VP/VS ratio, P- and S-wave impedances). Undeformed coal and TDCs with different deformation types (brittle, shear, and plastic deformations) show significant differences in their petrophysical parameters, and cross-plot analysis can directly differentiate them. As with traditional geological methods, acoustically measured petrophysical parameters are good indicators to determine the type of coal deformation. However, the TDCs with the same deformation type have similar petrophysical parameters; it is not easy to distinguish them directly. Instead, the proposed method incorporating principal component analysis and clustering can accurately distinguish up to five classes of TDCs. Different types of tectonic deformation environments and their intensities are highly correlated with the clustering results. This paper also provides essential petrophysical parameters for undeformed coal and TDCs in the Huaibei coalfield, and these parameters can help interpret undeformed coal and TDCs using wireline logs and seismic data. [ABSTRACT FROM AUTHOR]

Shale-rich reservoirs present a long-standing challenge for reservoir geologists because the clay minerals often induce a large-scale heterogeneity in the reservoir pore system. This work aims to understand the impact of clay distribution and mineralogy which would enhance the predictability of the best reservoir facies. We integrate seismic, well-log datasets to investigate the petrophysical characteristics of the clay-rich Cenomanian Clastics in the GPY oil field, north Western Desert of Egypt. These Clastics comprise the sandstone intervals which are the most prolific hydrocarbon reservoirs. Seismic data were used to interpret the main structural patterns as well as the different seismic facies. The well log data were utilized to interpret the lithologic variations and the type of clays in the reservoir as well as the different petrophysical parameters. Based on variations in their lithological and petrophysical characteristics, the Bahariya sandstones were sub-divided into three different rock units: Bahariya-3 (B-3), Bahariya-2 (B-2), and Bahariya-1 (B-1), separated by thick laminated clay intervals. AR/G Member is dominated by clays with relatively lower reservoir quality. Spectral gamma ray log values reveal that smectite is the dominant clay mineral in all the studied intervals. Laminated clays are dominant in B-1 and B-2 units, whereas, B-3 unit and Abu Roash G Member are enriched in structural clays. The quartzose sand content decreases from B-3 to AR/G and clay content increases from B-3 to AR/G. Therefore, the best reservoir facies and fluid flow conduits with best pore system characteristics are hosted in B-3 and the smectite clay streaks act as a good seal for hydrocarbons in the quartzose sandstone pay zone. [ABSTRACT FROM AUTHOR]

The purpose of this review paper is to show the possibilities of carbonate reservoir characterization using well logging and laboratory measurements. Attention was focused on standard and new methods of well logging acquisition and interpretation including laboratory experiments to show a part of the history of carbonate rock investigations as hydrocarbon or water reservoirs. Brief information on the geology, mineralogy and petrography of carbonate rocks was delivered. Reservoir properties, i.e., porosity (including fracturing), permeability, and saturation, were defined to emphasize the specific features of carbonates, such as fractures, and vugs. Examples of methodologies were selected from the commonly used laboratory techniques (thin sections examination, mercury and helium porosimetry, X-ray diffraction—XRD) combined with the standard well logs (bulk density—RHOB, neutron porosity—NPHI, sonic slowness—DT, and deep resistivity—Rd) to show the methods that have been used since the very beginning of the scientific and engineering studies of carbonates. Novelty in well logging, i.e., resistivity and acoustic imaging, nuclear magnetic resonance–NMR, dipole shear sonic imaging–DSI, and a spectral neutron-gamma log-geochemical device–GLT combined with modern laboratory investigations (NMR laboratory experiments, scanning electron microscopy SEM), showed how continuous information on mineral composition, porosity and saturation could be obtained and juxtaposed with very detailed laboratory data. Computed X-ray tomography (CT) enabling the 2D and 3D analyses of pores and fractures was presented as a quantitative methodology, effective in pore space characterization, revealing rock filtration abilities. Deep learning and artificial intelligence were used for joining various types of data. It was shown that thanks to new computational technologies original data from very small samples (micro scale), extensively describing the flow ability of the reservoir, could be extended to mezzo scale (core samples) and macro scale (well log images). Selected examples from the published papers illustrated the review. References cited in the text, together with the issues included in them, were the rich source of the practical knowledge processed These were checked by the authors and could be used in other projects. [ABSTRACT FROM AUTHOR]

The tectonic deformation has a significant influence on the hydrocarbon reservoirs properties. The effect of this process focuses on the lateral distribution of the petrophysical parameters characterizing the hydrocarbon reservoirs. The main objective of the current study is to perform a petrophysical examination of the Abu Madi gas reservoir which is the greatest gas-bearing reservoir at Nile Delta Basin in order to examine how far the Messinian tectonics affected the lateral variations of these petrophysical parameters. This petrophysical evaluation was performed based on the wireline log data acquired for five wells, namely, Abu Madi-2, Abu Madi-7, El Qara-3, Nidoco-7, and Nidoco-9 drilled within the Abu Madi Paleo-Valley. The petrophysical assessment for the most promising zone intervals within the Abu Madi sandstones in the inspected wells show that the total porosity varies between 17% and 22%, the effective porosity ranges from 7% to 19%, the shale volume fluctuates between 16% and 30%, hydrocarbon saturation varies from 37% to 76%, and the bulk volume of water varies between 0.02 and 0.09. These significant variations in the petrophysical properties of the Abu Madi reservoir are attributed to the tectonic influence during the deposition of the Abu Madi Formation as a part of the Late Miocene syn-rift megasequence in the Nile Delta Basin. This conclusion confirms that the petrophysical properties of sandstone reservoirs are function of tectonic and structural deformation.

Although geothermal energy has many clear advantages, including its sustainability and environmentally friendly nature, research into potential geothermal resources across the Longgang Block, Northeast China, has been limited. Here we present the first analysis of the potential geothermal resources in this region that employs joint geological and non-seismic geophysical methods to identify target areas that may be economically viable. We acquire and analyze high-precision gravity, magnetic, and magnetotelluric sounding data, which are constrained using the petrophysical parameters of outcropping rocks across the Longgang Block, to conduct a comprehensive evaluation of the region’s deep geological structures and their geothermal resources potential, with a focus on identifying faults, rock masses, and thermal storage structures. We find that Archean granitic gneiss and Mesozoic rock masses in the deeper section of the Longgang Block possess weak gravity anomalies and high resistivities. We also identify thermal storage structures near these deeper geological units based on their extremely low resistivities. The data are used to infer the dip and depth of known or hidden faults, to constrain the spatial distribution of intrusive rock masses, and to determine the spatial distribution of subsurface thermal storage structures. The potential of the target areas for geothermal resources exploitation is divided into three grades based on contact depths between faults and thermal storage structures, and the scale of their thermal storage structures. Our results suggest that a joint non-seismic geophysical approach can be effective in locating and evaluating geothermal resources in complex geological settings.

The study of petrophysical parameters plays a major role in the evaluation of hydrocarbon reservoirs. In this study, using well data in Geolog software, the petrophysical parameters of the Arab Formation (equivalent to Surmeh) in one of the oil fields in southern Iran were studied in two ways. Based on the petrophysical evaluation and using conventional cross-plots (neutron-density) and histogram of porosity and water saturation, the lithology of the Arab Formation was determined. The lithology consists of a combination of calcite, dolomite, and anhydrite. Comparison of the results of porosity changes is more consistent with the values obtained from core analysis. According to the calculated petrophysical properties, the upper part of the Arab (Surmeh) Formation was divided into seven parts. Comparison of water saturation showed that in all zones, the range of changes is high. By comparing the zones quality, zones 5 and 6 are introduced as the best reservoir zones. [ABSTRACT FROM AUTHOR]

Purpose. The research is aimed at evaluating the petrophysical characteristics of the Late Cretaceous Matulla Formation in the central part of the Gulf of Suez in order to detect its hydrocarbon reservoir potential. Methods. Well logs from five wells (Muzhil-1, -2, -4, -7, -8) were used to evaluate the Matulla reservoirs based on a computerized approach. Petrophysical parameters and fluid types were calculated, verified using core data, and represented vertically as lithosaturation cross plots and laterally as isoparametric variation maps. Findings. Evaluation of total porosity (Ft), effective porosity (Fe), shale content (Vsh), water saturation (Sw), permeability (K), bulk volume of water (BVW), and net pay characteristics of Matulla Formation in the Muzhil wells showed the following weighted average values: 18-23%, 15-19%, 21-40%, 20-100%, 1.1-281 mD, 3-21% and 0-83 ft, respectively. The Log-derived lithology identification indicates that the major matrix component of the Matulla Formation is quartzose sandstone with minor shale and carbonate contents. The upper zone is a poor reservoir, while the middle and lower zones are considered good reservoirs in all studied wells. It is expected that Muzhil-2 will produce oil without water; however, Muzhil-1 and Muzhil-4 will produce oil with water; while Muzhil-7 and Muzhil-8 will produce water only. Originality. Detailed log-derived petrophysical evaluation, verified by core analysis and well tests (DST and MDT), construction of lithosaturation cross plots for each well and isoparametric petrophysical maps are performed for the first time for Matulla Formation in the Muzhil field. Practical implications. The obtained results on lithosaturation and petrophysics have expanded the knowledge about the characteristics of the Matulla Formation sediments, hosting promising reservoir intervals, and should be taken into account in future exploration and development of the Muzhil field. [ABSTRACT FROM AUTHOR]

Estimation of reservoir parameters (reservoir characterization) including lithology, porosity and water saturation is crucial in the oil and gas industry. These parameters can be calculated in the wells and/or laboratories but these methods are time-consuming, costly, and can cover only a small part of the reservoir. Therefore, integration of seismic and well data for reservoir characterization has received special attention in the oil and gas industry since it provides information from the entire volume of the reservoir. In this study, to establish a relationship between the seismic attributes and the petrophysical parameters of a reservoir at the location of the wells, seismic inversion was performed using model-based, linear programming sparse spike, and maximum likelihood sparse spike algorithms, and the acoustic impedance were calculated accordingly. The model-based inversion method has provided a better answer than the other two methods by providing 99% correlation between the actual and estimated acoustic impedance. Therefore, this method was used to calculate the acoustic impedance in the space between the wells. In the next step, porosity, water saturation, and lithology (quartz and dolomite volume) were estimated from different seismic attributes. In this paper, the multi-attributes regression (MAR) method and artificial neural network (ANN) were used to estimate each of the petrophysical parameters of the reservoir, and we found out that the ANN provided a more accurate estimate than the MAR method for our given dataset. The correlation between the actual and estimated values using the ANN method for porosity, water saturation, quartz volume and dolomite volume is 86, 93, 93 and 95% respectively in the training data and 75, 78, 79 and 82% in the validation data. [ABSTRACT FROM AUTHOR]

The Abu Qir Bay area is on the offshore western part of the Nile Delta. It is divided into three fields namely: North Abu Qir, Abu Qir, and West Abu Qir. The main reservoir in the Abu Qir Bay area is Abu Madi Formation, which represents the Miocene rocks. The current uses conducting advanced conventional petrophysical techniques for determining the reservoir properties of the Abu Madi Formation. The wireline log data is commencing four wells drilled in the study area namely: North Abu Qir-7x, West Abu Qir-1x, Abu Qir-1x, and Abu Qir-13x). The interpreted lithologic data of the studied wire-line logs shows that the Abu Madi Formation’s main lithology consists of sandstone interbedded with some amounts of shale and thin lamina of limestone and anhydrite. Based on the interpreted well logging records, the Abu Madi Formation can be subdivided into three members: The Upper, Middle, and Lower Abu Madi members. The main target is the Upper Abu Madi members with shale volume varying from 8 to 12% with an average of 10%. The Middle Abu Madi member which is considered the second target has a shale volume ranging from 9.5 to 13.5% with an average of 11.5%. The thickness of the Abu Madi Formation ranges in the four drilled wells varies between 67.61 and 167.63 m with an average of 117 m. The petrophysical evaluation displays two important pay zones, and they belong to the Upper and the Middle Abu Madi members. The average porosity and hydrocarbon saturation values of both members indicate that Abu Madi is a very good reservoir. The southwestern area near West Abu Qir-1x well was found a good place for any upcoming appraisal, particularly for the upper Abu Madi reservoir future development. [ABSTRACT FROM AUTHOR]

The current findings emphasize interpreting wireline logs to assess the hydrocarbon prospect of the Lower Cretaceous Yageliemu Formation in the Yakela (YKL) gas condensate field, Tarim Basin, China. The present study consists of wireline logs of four drilled wells (S4, YK13, YK21, and YK32) and numerous reservoir zones have been comprehended. According to the petrophysical evaluation, the gas-bearing zone has high resistivity values, good porosity (Φeff) and permeability (K), low water content (Sw), and less shale content (Vsh) indicating clean sand. The petrophysical parameters of the interest zones were closely studied which are classed as good-quality sand layers with ranging effective porosities from 4.5 to 10%, permeability ranging from 0.5 to 18 mD, water saturation concentrations ranging from 55 to 59%, and the average value gas is 41–50%. The Archie equation was accurately tested to estimate water saturation in the reservoirs, revealing that in each well, Sw is less than 60%; therefore, the efficiency of the gas-bearing sand is of good quality. Lithofacies, horizontal and vertical variations of reservoir parameters, are evaluated through building self-organizing maps, isoparametric maps of the petrophysical parameters, and litho-saturation cross-plots, respectively. Isoparametric maps assist in visualizing the spatial distribution of the reservoir configuration. It is suggested that more wells be drilled in the southwestern and northwestern parts of the current research area. Due to the high water concentration and shale volume, the northeastern and southeastern portions of the understudied area must be overlooked. [ABSTRACT FROM AUTHOR]

This study identified the fluid types and boundaries present within selected reservoirs in Langbodo field, using petrophysical parameters based on estimated rock properties such as porosity, permeability, irreducible water saturation, hydrocarbon saturation and bulk water volume. This was with a view to correcting the salient reservoirs heterogeneities anomalies error inherent in building of an ideal realistic reservoir models. The quality of the data obtained were checked and despiked to eliminate null values. Petrel version 2009 and OpendTect 4.6.0. Exploration and production softwares were used for the quality interpretations of data, such as lithology identification, delineation of potential reservoirs and determination of fluids and fluids contacts. Estimation of quantitative petrophysical parameters were done by inputting the data into Microsoft excel 2015 version softwares and adopting appropriate mathematical relations, such as the Tixier, Timur and the Coates and Dumanoir models for the permeability (K). Realistic estimation of the permeability was done by comparing the average of the Tixier, Timur and the Coates and Dumanoir models with each of the models. The composite model obtained, mirrors the behavior of the Timur’s permeability which is higher than that of the Tixier and the Coates and Dumanoir. Integration of the Achie’s equation and neutron – density crossplot confirmed the presence of substantial hydrocarbon in the reservoirs, although producibility indicators revealed that the reservoirs may not be producible without enhanced oil recovery method(s). This study established that the composite model is a better representation of K in the study area because it agrees with the Timur’s estimation model.

This study aims to determine the petrophysical characteristics of the three wells in the Kifl Oilfield, central Iraq. The well logs were used to characterize hydrocarbon reservoirs to assess the hydrocarbon prospectivity, designate hydrocarbon and waterbearing zones, and determine the Nahr Umr Formation's petrophysical parameters. The Nahr Umr reservoir mainly consists of sandstone at the bottom and has an upper shale zone containing a small proportion of oil. The geophysical logs data from three oil wells include gamma-ray, resistivity, neutron, density, acoustic, and spontaneous potential logs. A gamma-ray log was employed for lithology differentiation, and a resistivity log was used to determine the response of distinct zones' productivity. The petrophysical parameters of shale volume, total porosity, effective porosity, water saturation, hydrocarbon saturation, and flushed zone saturation were evaluated using computer processing analyses (CPI). These parameters were plotted by interactive petrophysics (IP) software. The effective porosity (PHE) in the sandstone unit ranges between 3.2 and 31.2%, water saturation (SW) ranges between 6.6 and 100%, and hydrocarbon saturation and (Sh) range from 6 to 65%. The Nahr Umr Formation has moderate to low reservoir characteristics in the lower sandstone unit. [ABSTRACT FROM AUTHOR]

Tectonically deformed coal (TDC) is closely related to gas outbursts. Since TDC exploration is an essential objective for coalfield exploration, it is of great significance to study the petrophysical properties of TDCs and explore their differences. This study collected 17 TDCs and undeformed coal samples from the Huaibei coalfield and ultrasonically tested their petrophysical parameters, including densities, P- and S-wave velocities, and their derived petrophysical parameters (VP/VS ratio, P- and S-wave impedances). Undeformed coal and TDCs with different deformation types (brittle, shear, and plastic deformations) show significant differences in their petrophysical parameters, and cross-plot analysis can directly differentiate them. As with traditional geological methods, acoustically measured petrophysical parameters are good indicators to determine the type of coal deformation. However, the TDCs with the same deformation type have similar petrophysical parameters; it is not easy to distinguish them directly. Instead, the proposed method incorporating principal component analysis and clustering can accurately distinguish up to five classes of TDCs. Different types of tectonic deformation environments and their intensities are highly correlated with the clustering results. This paper also provides essential petrophysical parameters for undeformed coal and TDCs in the Huaibei coalfield, and these parameters can help interpret undeformed coal and TDCs using wireline logs and seismic data.

The purpose of this review paper is to show the possibilities of carbonate reservoir characterization using well logging and laboratory measurements. Attention was focused on standard and new methods of well logging acquisition and interpretation including laboratory experiments to show a part of the history of carbonate rock investigations as hydrocarbon or water reservoirs. Brief information on the geology, mineralogy and petrography of carbonate rocks was delivered. Reservoir properties, i.e., porosity (including fracturing), permeability, and saturation, were defined to emphasize the specific features of carbonates, such as fractures, and vugs. Examples of methodologies were selected from the commonly used laboratory techniques (thin sections examination, mercury and helium porosimetry, X-ray diffraction—XRD) combined with the standard well logs (bulk density—RHOB, neutron porosity—NPHI, sonic slowness—DT, and deep resistivity—Rd) to show the methods that have been used since the very beginning of the scientific and engineering studies of carbonates. Novelty in well logging, i.e., resistivity and acoustic imaging, nuclear magnetic resonance–NMR, dipole shear sonic imaging–DSI, and a spectral neutron-gamma log-geochemical device–GLT combined with modern laboratory investigations (NMR laboratory experiments, scanning electron microscopy SEM), showed how continuous information on mineral composition, porosity and saturation could be obtained and juxtaposed with very detailed laboratory data. Computed X-ray tomography (CT) enabling the 2D and 3D analyses of pores and fractures was presented as a quantitative methodology, effective in pore space characterization, revealing rock filtration abilities. Deep learning and artificial intelligence were used for joining various types of data. It was shown that thanks to new computational technologies original data from very small samples (micro scale), extensively describing the flow ability of the reservoir, could be extended to mezzo scale (core samples) and macro scale (well log images). Selected examples from the published papers illustrated the review. References cited in the text, together with the issues included in them, were the rich source of the practical knowledge processed These were checked by the authors and could be used in other projects.

The estimation of non-stationary random medium parameters of petrophysical parameters is the key to the application of random medium theory in fine seismic exploration. We proposed a method for estimating non-stationary random medium parameters of petrophysical parameters using seismic data. Based on the linear petrophysical model, the relationship between seismic data and porosity, clay volume, and water saturation in the random medium was described, and the principle and method of estimating the autocorrelation parameters of the petrophysical parameter random medium were introduced in this study. Subsequently, the specific steps of applying the power spectrum method, for parameter estimation in non-stationary random media with petrophysical parameters, were explained. The feasibility and correctness of the method were verified through the estimation test of the two-dimensional theoretical model. Eventually, the estimation test of non-stationary random medium parameters of petrophysical parameters was carried out by field seismic data, and the results indicated that the non-stationary random medium parameters can better portray the information of subsurface medium petrophysical parameters. The method can provide a reference for the construction of a priori information on petrophysical parameters, and it can also provide a theoretical basis for the in-depth application of random medium theory to practical data. [ABSTRACT FROM AUTHOR]

The Nubian Sandstone Aquifer (NSA) is the main freshwater resource in many parts of the Western Desert of Egypt including the Bahariya Oasis which attracted considerable attention during the recent decades. We determined several petrophysical parameters for the aquifer systems in the Bahariya Oasis using resistivity and gamma-ray logs. Geophysical logs recorded at 24 wells in the Bahariya Oasis are used to calculate the vertical thicknesses, total and effective porosities, permeability, shale volume, rock and formation water resistivities, and the total dissolved solids (TDS) in the different sandstone aquifers and shale beds. The logs of ten deep wells drilled in the northern part of the Bahariya Oasis enabled us to identify three aquifer zones separated by two shale beds. Only one aquifer and a shale bed are detected in the southern part of the oasis due to the limited number and the shallow penetration of wells. The shallow aquifer, referred here to as sand I, is detected in all wells with an average thickness of 184 m, moderate/high total and effective porosities, and low amount of total dissolved solids. The shale volume in the sand I aquifer increases towards the northeast but is low in the central and western parts of the Bahariya Oasis. The total dissolved solids are also low especially in the south; hence, this zone represents a suitable aquifer in the entire Bahariya Oasis. Being consistent with previous hydrogeological studies, our results indicate that the NSA in the southwestern part of the Bahariya Oasis contains potential lower-TDS shallow freshwater reserves compared to the aquifer of the northeastern part of Bahariya. [ABSTRACT FROM AUTHOR]

Seismic inversion is a geophysical technique used to estimate subsurface rock properties from seismic reflection data. Seismic data has band-limited nature and contains generally 10–80 Hz frequency hence seismic inversion combines well log information along with seismic data to extract high-resolution subsurface acoustic impedance which contains low as well as high frequencies. This rock property is used to extract qualitative as well as quantitative information of subsurface that can be analyzed to enhance geological as well as geophysical interpretation. The interpretations of extracted properties are more meaningful and provide more detailed information of the subsurface as compared to the traditional seismic data interpretation. The present study focused on the analysis of well log data as well as seismic data of the KG basin to find the prospective zone. Petrophysical parameters such as effective porosity, water saturation, hydrocarbon saturation, and several other parameters were calculated using the available well log data. Low Gamma-ray value, high resistivity, and cross-over between neutron and density logs indicated the presence of gas-bearing zones in the KG basin. Three main hydrocarbon-bearing zones are identified with an average Gamma-ray value of 50 API units at the depth range of (1918–1960 m), 58 API units (2116–2136 m), and 66 API units (2221–2245 m). The average resistivity is found to be 17 Ohm-m, 10 Ohm-m, and 12 Ohm-m and average porosity is 15%, 15%, and 14% of zone 1, zone 2, and zone 3 respectively. The analysis of petrophysical parameters and different cross-plots showed that the reservoir rock is of sandstone with shale as a seal rock. On the other hand, two types of seismic inversion namely Maximum Likelihood and Model-based seismic inversion are used to estimate subsurface acoustic impedance. The inverted section is interpreted as two anomalous zones with very low impedance ranging from 1800 m/s*g/cc to 6000 m/s*g/cc which is quite low and indicates the presence of loose formation. [ABSTRACT FROM AUTHOR]

The Mamuniyat sandstones represent the main reservoir in the "A" Oil Field, NC115 Concession, Murzuq Basin of Libya. As a result, the primary objectives of the current work are to evaluate and define the Mamuniyat Formation's petrophysical parameters using well-logging analysis. For this study, the available well-logging data from ten exploratory wells were provided. Several cross-plots were used to evaluate the lithologic constituents and fluid saturations in the form of litho-saturation cross-plots, and their output parameters were fed as inputs for Interactive Petrophysics (IP) software. According to the output results, the Mamuniyat Formation is primarily composed of sandstones with a few shales. These sandstones are generally fine- to coarse-grained, as indicated by the cross-plots, with a coarsening-upward sequence. According to the litho-saturation analysis, the Mamuniyat Formation is primarily oil-bearing with some levels of water-bearing sand. The petrophysical parameters derived from well-logging data agree with those derived from core sample analysis, demonstrating that the Mamuniyat Formation is a good reservoir. [ABSTRACT FROM AUTHOR]

An integrated seismic and petrophysical study using data from six wells has been carried out across 'Famito' field, Niger Delta Basin. The seismic data was incorporated with porosity and water saturation logs to characterize three hydrocarbon-bearing reservoirs and quantitatively estimate its prospectivity. The reservoirs (F-1000, G-1000, and H-1000) were correlatable across the field with some appreciable reduction in net sand down dip. F-1000 sandstone, the primary reservoir, was partitioned into five different zones (Top 301 to Top 305) to characterize the reservoir properties better. Structural analysis has been carried out using seismic data, which aided the mapping of major, antithetic, and synthetic faults with three horizons (constrained by well log data) that were gridded to create top structural maps. Petrophysical results using well log derived parameters and time-depth structural maps were obtained. Surface attributes, which are highly amplitude supported, were utilized to capture prospective zones better. The study showed that reservoir F-1000 has very good porosity (22–28%), appreciable shale volume (25–33%), and high hydrocarbon saturation (47–90%) with an oil and gas phase. Similarly, G-1000 and H-1000 comprises shaly sands with very good average porosities (25% and 24%, respectively) and high average hydrocarbon saturations (66% and 71%, respectively). Unlike G-1000, which showed an oil and gas phase, H-1000 contains only oil. Surface attribute analysis reveals the existence of hydrocarbon-bearing closures characterized by moderate to high root mean square amplitude and average energy values within G-1000 and H-1000, at the western part of the field. These values are closely consistent with those obtained for F-1000, which hosts the producing wells. Using these methods, this study has unravelled new prospective zones within reservoirs G-1000 and H-1000, allowing for increased hydrocarbon volumes from the already producing oil field. [ABSTRACT FROM AUTHOR]

Reservoir elastic parameters and gross rock volume (GRV) calculation are useful methods for measuring lithology and estimating hydrocarbon deposits in a reservoir. Using well log and seismic data, in the present study rock physics and GRV are applied to the B-Sand, which is part of the Lower Goru Formation. For wells Dars West-01 and Jumman Shah-01, the reservoir B-Sand depth is estimated to be between 1852–1944 m and 1534–1618 m, respectively. As a result, it is important to use well log cross-plots to reliably delineate the sand body and measure the petrophysical properties of the mapped sandstone intervals within the formation. These cross-plots were used to differentiate between hydrocarbon-filled and water-filled sandstone. The numerous rock physics cross-plots are used to differentiate between gas sand, oil sand, brine, and shale. Petrophysical analysis shows that reservoir has good porosity and holds significant amount of hydrocarbon but is water wet. Some of the rock properties cross-plotted together show a linear relationship and do not differentiate easily regarding lithology, while the remainder of the cross-plot shows that the reservoir is predominantly sand with very few traces of shale. GRV and original gas in place (OGIP) are calculated in B-Sand which reveals that Dars West-01 as compared to Jumman Shah-01 holds not only a significant amount of hydrocarbon but is also less saturated with water. The present study shows that the cross-plots and GRV approach can be used to accurately delineate reservoirs for further formation evaluation and for the estimation of reserves. It therefore means that an outright estimation of petrophysical properties on wrongly delineated reservoirs can significantly affect the porosity, permeability, pore-size geometry, and net-to-gross ratio and reserve estimation. [ABSTRACT FROM AUTHOR]

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Hydrocarbon prospect, analysis and characterization are entailed in the processes used in identifying and delineating features/structures in the subsurface that are likely to be potential hydrocarbon reservoirs. The research was done by analyzing and interpreting well logs and seismic data obtained from Kolo Creek. Well logs were used to identify the lithologies present, sand and shale using the gamma ray log, potential hydrocarbon zones were interpreted using the resistivity log. These identified zones were taken into consideration for Petrophysical evaluation in which parameters such as porosity, permeability, water, and hydrocarbon saturation were obtained as details in the four wells. The lithologies were correlated across the four wells to define the continuity of the identified pay zones. Seismic-to-well tie was done using checkshot data obtainable in only Well-2. Three payzones were identified and the fluid types being gas, oil and water. Porosity values ranges from 20% to 34%, water saturation obtained were within the range of 24% and 40%, and hydrocarbon saturation (defined as whole minus water saturation) ranged from 60% to 76%. These values showed that the hydrocarbon was present in commercial quantity hence production can take place. Three horizons were picked, six faults labelled A-F, four synthetic and two antithetic were identified across the seismic sections. The horizons were studied in detail, for time, depth and attribute studies. Time structural map was generated,and it showed anticlinal structure present at its center. Depth map generated also depicted information as revealed by the time map thus validating the presence of hydrocarbon. An extracted attribute map indicated areas of high amplitudes and bright spots area being indicative of hydrocarbon accumulation present. The volumetric results showed that Reservoir A had OOIP of 467 x 106 STB and STOOIP of 389 x 106 STB. [ABSTRACT FROM AUTHOR]

Simulation is an art to model the reservoir's structure in the petroleum industry, which transfers all possible data digitally to the reservoir management system's suitable computation software. The present study attempts to construct a 3D structural model using the geostatistical method to access in situ oil volume and the best oil production position. The geological area is the Maroon oilfields located at Dezful Embayment in southwest of Iran. In this oilfield, the Asmari reservoir is divided into ten zones. Several steps such as griding, kriging, and experimental variogram were carried out to access all available data to make up the model. The evaluation revealed that zones one and five were the main oil-bearing layers since it contains about 60% of total oil volume in this field. Petrophysical parameter distribution indicated that zones four and seven are good candidates for oil production since they have higher porosity and net to growth thickness than other zones. From the seventh to the tenth zone, the oil volume decreased due to high water saturation in these areas. The best zones for the future program are located in the western part. This study shows that 3D modeling will find elongation-type anticline and reservoir direction and the best location for future drilling programs based on the interaction of the petrographic parameters. The results can be used in various steps during the lifetime of the different reservoirs around the globe. [ABSTRACT FROM AUTHOR]

• A new NMR relaxation theory of shale oil is proposed and verified. • The effects of pyrite and clay minerals on NMR response are analyzed. • Petrophysical parameter conversion model between laboratory and downhole instruments was established. Shale oil reservoirs, characterized by a low porosity, complex mineral composition, and heterogeneity of organic matter distribution, are common unconventional oil and gas reservoirs. Nuclear magnetic resonance (NMR) methods have great potential for the evaluation of petrophysical parameters in porous rocks. However, it is challenging to characterize the petrophysical properties of shale oil due to the complex mineral composition and heterogeneity of organic matter distribution. In this paper, a new NMR relaxation theory for shale was proposed for the first time, and the frequency dependencies of transverse surface relaxivity and internal magnetic field gradient for pore fluids were presented. The accuracy was verified by the extraction experiments, gas chromatography experiments, and multi-frequency NMR experiments for the first time. These experiments were also utilized to determine the transverse surface relaxivity and the transverse bulk relaxation time. Subsequently, the effects of the pyrite and clay minerals on shale oil T 2 distributions at different instrument frequencies were analyzed with random walk simulations based on digital core technology for the first time. The results show the echo spacing, instrument frequency, pyrite content, and clay minerals are important parameters affecting the NMR response. Compared with the oil in organic pore, these factors have a greater impact on the NMR response characteristics for water in inorganic pore. When the content of pyrite is 5.3 % and the echo spacing is 0.2 ms, the numerical simulation results show that the NMR porosity of water in inorganic pore is 65.3 %, 12.3 %, and 1.6 % of the real porosity at the instrument frequencies (IF) of 2 MHz, 21.36 MHz, and 200 MHz, respectively. When chlorite with high magnetic susceptibility exists near the formation pores, it can also affect the NMR response of shale oil. The results show the effects of these factors on porosity and T 2ML are non-negligible. The cross-plots of petrophysical parameters correction from shale oil T 2 distributions were established for the first time. This work provides a theoretical guide for the NMR-based shale oil evaluation, which may be helpful for petrophysical parameter conversion between downhole and laboratory NMR instruments. [ABSTRACT FROM AUTHOR]

The estimation of non-stationary random medium parameters of petrophysical parameters is the key to the application of random medium theory in fine seismic exploration. We proposed a method for estimating non-stationary random medium parameters of petrophysical parameters using seismic data. Based on the linear petrophysical model, the relationship between seismic data and porosity, clay volume, and water saturation in the random medium was described, and the principle and method of estimating the autocorrelation parameters of the petrophysical parameter random medium were introduced in this study. Subsequently, the specific steps of applying the power spectrum method, for parameter estimation in non-stationary random media with petrophysical parameters, were explained. The feasibility and correctness of the method were verified through the estimation test of the two-dimensional theoretical model. Eventually, the estimation test of non-stationary random medium parameters of petrophysical parameters was carried out by field seismic data, and the results indicated that the non-stationary random medium parameters can better portray the information of subsurface medium petrophysical parameters. The method can provide a reference for the construction of a priori information on petrophysical parameters, and it can also provide a theoretical basis for the in-depth application of random medium theory to practical data.

Safir Oil Field which locates within Shushan Basin is considered one of the well-known oil fields in northern Western Desert of Egypt. Alam El Bueib 3A Member is the main oil producer in this field. This member in Safir-N07 well has water saturation (Sw) values less than 40% with 17% porosity. However, the available data of Drill Stem Test (DST) indicate that 999 barrels water per day (BWPD) and only one barrel oil per day (BOPD) of total 1000 barrels fluid per day (BFPD) were produced. This represents a challenging problem facing any petrophysicist. The presented article treats this situation by comparing water saturation with other two extremely important petrophysical parameters. These are the critical water saturation (Scw) and minimum bulk volume water (BVWmin). The critical water saturation (Scw) of the tested interval is 34%, which is less than the calculated Sw (i.e., Sw > Scw) that reflects the existence of water rather than oil. In addition, BVWmin has been calculated to be 0.05. The calculated BVW for AEB-3A Member (Φ × Sw) is 0.07 which is higher than the BVWmin value confirming the water productivity and matching the DST data. The presented technique was also applied to the same member in Safir-03 well in the same field. The calculated Sw and BVW are 12% and 0.03, respectively, which are lower than Scw (31%) and BVWmin (0.05) indicating that the reservoir is at irreducible state (no water will produced). During DST, this member recovered 1350 (BOPD) and zero (BWPD) confirming the importance and validation for the applied techniques. The constructed structure contour map shows a distinctive three-way closure in the southern part of the study representing a suitable place for hydrocarbon accumulation in Safir-03 well. On the other side of this map displays Safir-N07 well located in downthrown which proves oil-free production as residual oil saturation. [ABSTRACT FROM AUTHOR]

This study examines the evaluation of empirical equations related to primary seismic velocity with density and porosity. The empirical equations have been used in 128 sites based on a seismic grid covering the east Baghdad oil field. The average of density of the geological formations between each seismic reflectors and another (each interval) was extracted from well log data for four wells scattered in the field. Those reflectors were arranged from top to bottom of the studied Formations (Fatha, Hartha, Tanuma, Ahmadi, Shuaiba, and Gutnia Formations). In order to determine the best empirical equations, several previous equations were tested to obtain the best that correspond to the density rates taken from well records. The most suitable equations were used in calculating density for all intervals in the whole field. Using the strong relationship (porosity-density) taken from the well log data, the porosity values for all the studied intervals were found. Later, the porosity and density contour maps for each interval in the whole field were established. The locations of high porosity zones were identified and related to the petroleum distribution in the field. [ABSTRACT FROM AUTHOR]

The present study is an integrated approach to derive reservoir characteristics from well log data. The studied wells, Rajian-01, Daiwal-01, and Kal-01, have been drilled by the Oil and Gas Development Company Limited in the south-eastern part of Potwar Plateau. The petrophysical analysis of these three wells has been done on the basis of well logs (Gamma-ray log, resistivity log, density log, sonic log, and neutron log) which helps to evaluate the hydrocarbon saturations, water saturations, volume of shale, net pay, porosity, and permeability. Rajian-01 gives approximately 65% hydrocarbon saturation in the reservoir rocks. The most promising reservoir rocks of this well are Khewra Sandstone and Jutana Dolomite; the Tobra Formation, however thinly bedded, also acts as a reservoir. Daiwal-01 is an abandoned well and Khewra Sandstone, Jutana Dolomite, and Dandot Formation act as reservoir rocks, whereas the reservoir rocks in well Kal-01 comprises 68% hydrocarbon saturation. The best reservoir rocks in the Kal-01 are Khewra Sandstone, Jutana Dolomite, and Warchha Sandstone (poor to moderate reservoir intervals). The overall petrophysical analysis shows that Rajian-01 and Kal-01 have significant hydrocarbon potential, whereas Daiwal-01 well is uneconomical due to the structural complexity. The Khewra Sandstone and Jutana Formation in Rajian-01 and Kal-01 have favorable petrophysical characteristics for commercial hydrocarbon accumulation. The effective porosity in the Jutana Formation can be increased by induced fracturing. Fracturing work in the Jutana Formation can increase oil recovery. The detailed subsurface studies (including subsurface structure) will enable a better understanding of the hydrocarbon potential in the Potwar Plateau. [ABSTRACT FROM AUTHOR]

Evaluation of the petrophysical parameters in Uzot-field was carried out using Well log data. The target for this study was the D3100 reservoir sand of wells Uz 004, Uz 005, U008 and Uz 011 with depth range of 5540ft to 5800ft across the four wells. Resistivity logs were used to identify hydrocarbon or water-bearing zones and hence indicate permeable zones while the various sand bodies were then identified using the gamma ray logs. The results showed the delineated reservoir units having porosity ranging from 21.40% to 33.80% indicating a suitable reservoir quality; permeability values from 1314md to 18089md attributed to the well sorted nature of the sands and hydrocarbon saturation range from 12.00% to 85.79% implying high hydrocarbon production. These results suggest a reservoir system whose performance is considered satisfactory for hydrocarbon production. [ABSTRACT FROM AUTHOR]

Porosity and density information were taken from five well logs scattered in East Baghdad oil field. New empirical equations (porosity-depth, density-depth) were established for all the geological formations within the Tanuma-Ahmadi interval. The correlation coefficient (R) of these equations derived for each formation ranged from 0.04 to 0.61 which was attributed to variable lithological effects. The depth information for (126) velocity analysis sites covering the field were used to apply those new equations. After the new empirical equations were applied on the whole field, porosity and density contour maps for the period (Tanuma-Ahmadi) were produced. The locations of high porosity zones were identified and related to the compaction and petroleum distribution in the field. [ABSTRACT FROM AUTHOR]

Copyright of Anuario do Instituto de Geociencias is the property of Universidade Federal do Rio de Janeiro, Instituto de Geociencias and its content may not be copied or emailed to multiple sites or posted to a listserv without the copyright holder's express written permission. However, users may print, download, or email articles for individual use. This abstract may be abridged. No warranty is given about the accuracy of the copy. Users should refer to the original published version of the material for the full abstract. (Copyright applies to all Abstracts.)

Structural interpretation of 3-D seismic data and well log have been applied to unravel hydrocarbon entrapment pattern and petrophysical parameters of X-field within the coastal swamp region of the Niger Delta.. Four reservoir intervals (A, B, C and D) delineated as (W-026, 032, 042 and 048) using gamma ray and resistivity log response. Structural interpretation for inline 5158 revealed four horizons (A, B, C and D) and eight (8) faults labelled (F1, F2, F12, F13, F21, F22, F23, and F24) were mapped. It was observed that the hanging wall block due to reverse drag or rollover anticline slided over fault F12 and created fault F2, thereby creating subsidence where sediments can be deposited. Therefore, faults F2 and F12 created rollover structures which cuts across the entire four reservoirs and invaluably responsible for trapping of hydrocarbon in the field. RMS map developed for horizons 'A' and 'B' revealed high amplitude anomalies, while variance attribute for both horizons showed relatively uniform lithology observed from east to west across the study area. While from north-east to south west, variance was observed to increase relatively which indicates different lithology. These trend exposes dipping of the channel fill at both flanks by creating extensive faulting. Results of petrophysical evaluation for reservoirs 'A' and 'B' across the four wells were analyzed. For reservoir 'A', porosity values of 32.8%, 24.8%, 25.9% and 27.1% were obtained for wells W-048, 042, 026 and 032 respectively with an average of 27.65%, while for reservoir 'B' porosity values of 26.83%, 26.93%, 25.59% and 27.99% for wells W-048, 042, 026 and 032 were obtained respectively with an average of 26.84%. This porosity values were rated very good to excellent for reservoir 'A' and very good for reservoir 'B', while Permeability values of the order (K > 1000mD) were obtained for both reservoirs across the four wells and is rated excellent. Hydrocarbon saturation (Shc) across the four wells averages at 68.57% for reservoir 'A' and 68.67% for reservoir 'B' which is high. Log motifs using gamma ray log for well-026 was integrated with seismic facies to infer on depositional environment of the reservoirs horizons showed a combination of serrated funnel/blocky shape log response and coarsening upward cycles. For reservoirs 'A', 'B' and 'C' the log shape pattern indicates deposition in a fluvial / tidal, channel environment while for reservoir 'D' the pattern indicates deposition in deltaic front environment. Isochore maps computed for horizons 'A' and 'B', shows that horizon 'A' is relatively thick and this pattern suggests increased tectonic activities during deposition of reservoir 'A' and is an indication that reservoir 'A' is a synrift deposit. [ABSTRACT FROM AUTHOR]

Upper Safa Member is part of Jurassic Khatatba Formation; it consists of low net gross ratio sand streaks. The core and well logging data were used to perform a comprehensive reservoir evaluation. The Schlumberger application "Techlog" was used to perform the required evaluation analysis. Four oriented wells were selected for this study. The volume of shale "Vsh" using gamma-ray (GR) was used to evaluate the lithology and to discriminate sand "reservoir" from shale "non-reservoir". A porosity model using the density log was constructed and used as an input to calculate Archie's water saturation "Sw". Porosity- Permeability (Poro-Perm) Transform was used to evaluate the reservoir permeability. The net reservoir and net pay thicknesses were seen attractive in three out of four wells. The reservoir quality parameters "Porosity and Permeability" were different from well to well. The hydrocarbon saturation "Sh" was high in the three wells. The hydrocarbon intervals depths were highlighted and considered in the perforation strategy. [ABSTRACT FROM AUTHOR]

Assessing reservoir properties and knowing the relationship between different reservoir parameters can significantly help to plan for production from a reservoir. In this study, which was carried out on the gas reservoir of the Triassic Dahram Group at the South Pars Gas Field, in southern Iran, petrophysical parameters such as porosity, shale volume, saturation of water and hydrocarbon, as well as amount of different minerals in the reservoir sequence, were first calculated using the probabilistic evaluation method. In the second step, for the separation of the sequential electrofacies, the multi-resolution chart-based clustering method was used resulting in recognition of five electrofacies with different reservoir geological properties. The results obtained from the first and second steps showed that the no. 5 electrofacies (EF-5), which has clean lime lithology and has the lowest water saturation, good porosity and high gas volume, was considered as the best reservoir facies in the studied sequence. Therefore, by separation of electrofacies, a suitable relationship can be found between different geological facies and petrophysical parameters of the reservoir. [ABSTRACT FROM AUTHOR]

Copyright of Türkiye Jeoloji Bülteni is the property of TMMOB JEOLOJI MUHENDISLERI ODASI and its content may not be copied or emailed to multiple sites or posted to a listserv without the copyright holder's express written permission. However, users may print, download, or email articles for individual use. This abstract may be abridged. No warranty is given about the accuracy of the copy. Users should refer to the original published version of the material for the full abstract. (Copyright applies to all Abstracts.)

The article presents the methodology for the qualitative determination of fracture zones in the profiles of carbonate formations, based on the complex fracture analysis (CFA) method. Three additive fracture ranges were distinguished, characterized by successively increasing aperture and fracture length values, operatively named micro, meso and macro. Furthermore, the quantitative characterization of fractures with different apertures was done. The methodology of laboratory data integration, fracture porosity and fracture permeability measurements performed on thin section and polished section was described as part of the quantitative well logging data interpretation procedure which uses the FPI (fracture porosity index) parameter. The research was performed in the Lower Carboniferous limestone formation that builds the Paleozoic basement of the Carpathian orogeny. An original software dedicated to the analysis of the wellbore images, obtained with the XRMI Halliburton scanner, was used to identify the presence of macro-fractures, determine their aperture and estimate fractures porosity and permeability in the profile of the analyzed rock formation. As a result of the work, postulates regarding the methodology for collecting research material were formulated, in particular: the scope of different laboratory core samples measurements and well log types. The principles of the optimal methodology for identifying fractured zones and quantitative evaluation of petrophysical parameters of recognized fracture systems were defined. [ABSTRACT FROM AUTHOR]

Carbonate rocks, along with sandstone, constitute the main reservoirs of oil and gas in the world. Examination of petrophysical properties includes parameters such as porosity, permeability and fluid saturation, lithological variations according to depth and hydrocarbon properties including effective and ineffective thickness and effective hydrocarbons column. Asmari reservoir of Bibi- Hakimeh oilfield is one of the tertiary carbonate reservoirs in Iran located 210 km southeast of Ahwaz. The reservoir is divided into 8 zones, each zone having its own petrological characteristics and lithology. Considering the fact that all three major lithologies of reservoirs (limestone, dolomite and Shale) exist in the Asmari reservoir of Bibi- Hakimeh oilfield, lithological study and its impact on petrophysical parameters of reservoirs are very important. Based on the assessments, zone 1 with more than 85% limestone has the most effective hydrocarbon column, the highest net thickness and the highest net to total thickness ratio, and due to its low water saturation (about 20% for effective zones), it has the best reservoir quality among the other zones. Following zone 1, zones 2 and 3 take the second and the third places, respectively. Zones 4 to 8 are below the water-oil interface, hence they are not included in productive zones and have lower reservoir quality. Zone 1 is considered as the best oil producing layer with respect to petrophysical parameters. [ABSTRACT FROM AUTHOR]

Abstract In geothermic studies, the thermal conductivity (TC) is an essential parameter needed to calculate heat flow in rocks. It is obtained generally with high accuracy from laboratory measurements. The methodology proposed in this paper is to estimate the TC, which depends on many parameters; such as mineralogy, porosity, shape of voids and nature of contact between grains, based on linear and nonlinear relationships. In order to predict the thermal conductivity from other petrophysical parameters in the Hamra Quartzites reservoir, we have measured porosity, density and permeability, for dry samples taken from core wells. The correlation coefficients (R) were calculated between thermal conductivity and other petrophysical parameters for all samples. The results show that, the correlation coefficient is moderate between TC and the porosity, weak between TC, density and permeability. To improve these correlations, samples were classified into cemented and uncemented sets. A minor improvement on the correlation coefficients is noted between TC, density and porosity in uncemented samples, with values equal 0.51 and 0.73, respectively. The application of Radial Basis Function (RBF) neural networks, using density, porosity and permeability as inputs and thermal conductivity as output, permit us to predict the thermal conductivity with high precision. The correlation coefficient between TC estimated by the RBF neural network is the same as that measured in laboratory equaling 0.983. Highlights • Relationships between thermal conductivity and petrophysical parameters. • Effect of cementation on correlation between thermal conductivity and physical parameters. • Increase porosity decrease thermal conductivity in Hamra Quartzites reservoir. • The RBF neural network predicted thermal conductivity with high accuracy. [ABSTRACT FROM AUTHOR]

Abstract In this study, we investigate the petrophysical parameter values above which oil can accumulate, using a tight oil reservoir in the Jimusaer Depression, Junggar Basin, as an example. Statistical analysis of well-drilling data and effective porosity measurements is integrated with numerical simulations of force balance to illuminate the mechanisms that place a lower limit on the petrophysical parameters of tight hydrocarbon reservoirs. Further, we discuss the factors that influence these limits. The results show that when porosity is observed to be less than 5%, corresponding to a pore-throat radius of more than 0.2 μm, exploratory wells reach reservoirs comprising only water layers. The lower limit for oil accumulation is reached when irreducible water saturation reaches 100% and porosity is approximately 5%. This fits well with the values arrived at by modeling the force balance. In the reservoirs under consideration, oil charging is driven by excess pressure resulting from hydrocarbon generation and is resisted by capillary force. When the pore-throat radius is larger than 0.2 μm, the capillary force will be greater than the driving force, and tight reservoirs cannot be charged with oil. This corresponds to a porosity of approximately 5%, matching the results derived from observations. The values of these lower limits depend on many factors, such as source rock quality, depth, temperature, hydrocarbon-generation kinetics, and interfacial tension, and hence vary under different geological conditions. Thus, in lacustrine basins in China with type I kerogen-dominated source rocks, the lower limits are smaller than in those where other types dominate. Differences in the geothermal gradient mean that, at similar hydrocarbon-generation temperatures, the lower limits for reservoirs in Western China are smaller than for those in the east. There is also a smaller lower limitation porosity in tight gas reservoirs than in tight oil reservoirs due to the difference in interfacial tension. Highlights • Illuminate the mechanisms of the lower limits in tight hydrocarbon reservoirs. • Discuss the impact factors on lower limits of tight hydrocarbon reservoirs. • The lower limits of the P 2 l in Jimusaer are with throat radius of 0.2 μm and porosity of 5%. [ABSTRACT FROM AUTHOR]

Abstract The study of groundwater potential in Wadi El-Assiuoti is of a prime importance for both current and future development. In this paper the groundwater occurrences are investigated using integrated; 1) geophysical well logging (Self potential, Resistivity and Gamma Ray), 2) subsurface lithologic data and 3) hydraulic data (transmissivity, transmissibility, hydraulic conductivity and storativity) in addition to reviewing all studies on Wadi El-Assiuoti. Different petrophysical parameters (formation water resistivity, formation factor, porosity, permeability, salinity and shale volume) are computed. These parameters are very necessary to identify the aquifers characteristics in the surveyed area. The integration between geophysical and hydrogeological data shows the possibility of two water bearing formation (Quaternary and Plio-Pleistocene). Generally, porosity and permeability values of these aquifers decrease toward the west. The aquifers exist under unconfined to semi confined conditions. The wide range values of both well efficiency and hydraulic conductivity indicate heterogeneity in the lithology and hydraulic characteristics of the aquifer materials. The computed transmissibility values indicate that the water-bearing sediments in the area under investigation are generally of high productivity. In some localities due to the heterogeneity of sediment, the water-bearing sediments are of moderate productivity. Recently, due to the increase of drilling activities at the middle part of the studied area some problems concerning the groundwater potential and high salinity in the area are happening. Highlights • Groundwater is the only water source for sustainable development in Wadi El-Assiuoti. • Petrophysical and hydrogeological data were analyzed to study the water-bearing horizons. • Ground-water potentiality has been investigated in the study area. [ABSTRACT FROM AUTHOR]

Comprehensive utilisation of elastic and petrophysical parameters to predict favourable reservoirs can help reduce the possibility of misidentification of resources. Existing simultaneous inversion methods for estimating the elastic and petrophysical parameters are typically based on either the Gassmann equation, with which these parameters are inverted from prestack seismic data through stochastic optimisation methods, or Wyllie's modified equation, with which these parameters are inverted from poststack seismic data using deterministic optimisation methods. The purpose of this work is to develop a strategy for estimating the elastic and petrophysical parameters based on the Gassmann equation using deterministic prestack inversion. We employ the Gassmann equation to construct the relationship between the prestack seismic data and petrophysical parameters. We treat the joint posterior probability of elastic and petrophysical parameters as the objective function under a Bayesian framework. Given the macroscopic geological background and the poor-quality prestack seismic data, seismic facies regularisation constraints were introduced to improve the robustness and accuracy of the inversion. The very fast-simulated annealing method is used to quickly find the optimal solutions for the elastic and petrophysical parameters. Based on a model test and the application of real data demonstrates that the proposed inversion method has high accuracy and strong reliability. This paper describes the development of a deterministic prestack inversion for estimating elastic and petrophysical parameters. The Gassmann equation is used to construct the relationship between the seismic data and petrophysical parameters. Seismic facies constraints were introduced to improve the accuracy. The very fast-simulated annealing method is used to quickly find the optimal solutions. [ABSTRACT FROM AUTHOR]

The Nukhul Formation represents the sediments deposited during the earliest phase of the syn-rift period in the Gulf of Suez rift. It is the primary hydrocarbon reservoir for fifteen fields in the region. However, the timing of rifting needs to be better constrained, and the influence of local tectonics and global eustatic sea-level fluctuations on reservoir quality and deposition is still being determined. This research aims to establish a stratigraphic sequence framework, determine the age of the Suez Rift commencement, use changes in paleobathymetry, and assess reservoir quality. The methods employed involve the analysis of four boreholes in the Abu Rudeis-Sidri field, incorporating biostratigraphy, well-logs, and 3D seismic data. The integrated paleo-structure and biostratigraphic analyses indicate that the beginning of rifting in the Gulf of Suez occurred at 23.53 Ma at the first common occurrence (FCO) of Trilobatus primordius. The paleobathymetric analysis of the Nukhul Formation reveals deeper paleo-water depths during certain intervals, indicating deposition during a phase of high subsidence and rift-climax. The Nukhul stratigraphic sequence reflects sea-level changes leading to shifts in accommodation, and facies changes, erosion, and sequence formation during the late Chattian and early Burdigalian stages. However, the reservoir characterization of the Nukhul Formation is significantly affected by various factors, including cementation, pore system properties, sediment sorting, rift system geometry, and relative sea-level fluctuations. These factors must be carefully considered in any regional exploration or development efforts. The study also reveals that tectonic activity played a role in forming fault-bounded basins, and eustatic sea-level changes influenced the rate and timing of sediment accumulation. These findings can aid in predicting the distribution of the Nukhul sedimentary deposits and improve the ability to explore and develop their resources. • The initiation of the Suez rift occurred 23.53 Ma based on the FO of T. primordius. • The Study revealed deeper paleodepths during intervals of high subsidence and rift climax. • Local tectonics and global sea level changes were found to control sediment deposition. • The results contribute to understanding processes shaping sedimentary basins which can guide future exploration efforts. • Findings provide insights into evolution of rift basins and factors controlling sedimentation applicable to other basins. [ABSTRACT FROM AUTHOR]

Petrophysical investigations are fundamental to natural resource exploration. In order to recognise the geothermal potential of sedimentary rocks in central Poland, 259 samples were collected from prospective deep-lying geothermal reservoirs. Parameters measured include bulk density, skeletal density, effective porosity, permeability, average pore diameter and specific surface. Results indicate that at great depths (mostly > 3,000 m below surface) sedimentary rocks show low values of porosity (mainly less than 5%) and permeability (only sporadically in excess of 1 md). These values call for a petrothermal use of reservoirs, for which an Enhanced Geothermal System (EGS) was developed. Reservoirs suited for the EGS are Carboniferous and Lower Triassic sandstones in the central part of Poland (Mogilno-Łódź Trough region and a small part of the Kujawy Swell and Fore-Sudetic regions). In addition, Carboniferous limestones in this area are potentially prospective.