Effective Porosity Research Articles

Exploring the role of phosphorus in the clogging formation of subsurface flow constructed wetland by two-dimensional visualization technique

Phosphorus (P) is associated with microbial activity and can be retained in constructed wetland (CW) through adsorption and chemical precipitation. However, its potential impact on clogging remains poorly studied. In this study, a two-dimensional (2D) visualization technique was utilized to investigate the effect of P on clogging process inside subsurface flow constructed wetland (SSF-CW) during the operation. Tracer images analysis showed that the preferential flow pathway proportions of P-containing group (P-CW) and P-free group (C-CW) were 30.38 ± 1.07 % and 9.72 ± 0.47 %, respectively. The fractal dimension of preferential flow pathways in C-CW (1.57 ± 0.02) was lower than in P-CW (1.70 ± 0.03), indicating that the preferential flow pathways in P-CW exhibited more diversion and tortuosity. The removal efficiencies of both CWs exhibited an initial increase followed by a decrease, with P-CW generally demonstrating higher pollutant removal efficiencies. In P-CW, the primary pathway for P removal was chemical precipitation dominated by apatite P (CaP). Furthermore, the addition of P altered the composition of extracellular polymeric substances (EPS) and reduced the stability of microbial aggregates, resulting in higher effective porosity. This study provides new insights into the role of P in the clogging of SSF-CW and would contribute to optimizing CW clogging management.

Identifying payable cluster distributions for improved reservoir characterization: a robust unsupervised ML strategy for rock typing of depositional facies in heterogeneous rocks

The oil and gas industry relies on accurately predicting profitable clusters in subsurface formations for geophysical reservoir analysis. It is challenging to predict payable clusters in complicated geological settings like the Lower Indus Basin, Pakistan. In complex, high-dimensional heterogeneous geological settings, traditional statistical methods seldom provide correct results. Therefore, this paper introduces a robust unsupervised AI strategy designed to identify and classify profitable zones using self-organizing maps (SOM) and K-means clustering techniques. Results of SOM and K-means clustering provided the reservoir potentials of six depositional facies types (MBSD, DCSD, MBSMD, SSiCL, SMDFM, MBSh) based on cluster distributions. The depositional facies MBSD and DCSD exhibited high similarity and achieved a maximum effective porosity (PHIE) value of ≥ 15%, indicating good reservoir rock typing (RRT) features. The density-based spatial clustering of applications with noise (DBSCAN) showed minimum outliers through meta cluster attributes and confirmed the reliability of the generated cluster results. Shapley Additive Explanations (SHAP) model identified PHIE as the most significant parameter and was beneficial in identifying payable and non-payable clustering zones. Additionally, this strategy highlights the importance of unsupervised AI in managing profitable cluster distribution across various geological formations, going beyond simple reservoir characterization.

Permeability and Induced Polarization of Mudstones

AbstractElectrical measurements can be used to estimate hydraulic properties such as permeability (k) in sedimentary rocks. Previous work has focused on sandstones, siltstones, and carbonates, while investigations on mudstones have rarely been reported. In this study, we report on electrical geophysical measurements for 23 mudstone samples using an experimental approach designed to reliably saturate these low permeability mudstones. The modified Hagen‐Poiseuille model linking permeability to the formation factor (F) and an effective pore radius (r) provides an excellent fit to the data set with a near‐constant pore radius, indicating that the effective porosity (1/F) is the controlling factor on k. In these samples, the surface area normalized to pore volume (Spor), frequently used in permeability estimation models, varies by 1–2 orders of magnitude and is thus not a reliable proxy of the inverse effective hydraulic radius. The formation factor also exerts the primary control on induced polarization (IP) parameters, whereas Spor shows no relation to the IP parameters. A strong linear relationship is found between IP parameters (imaginary conductivity and normalized chargeability) and surface conductivity, although the proportionality factor is significantly lower than those observed in more permeable rocks and sediments. Apparent relationships between the polarization strength‐derived and time constant‐derived geophysical length scales and the effective hydraulic radius appear to be driven by variations in the electrochemical parameters (i.e., specific polarizability and diffusion coefficient). Overall, these findings emphasize that predicting hydraulic properties from electrical measurements in fine‐grained rocks remains challenging and requires further investigation into the electrochemical properties involved.

Evaluation and development of pedotransfer functions of saturated hydraulic conductivity for subtropical soils

The determination of soil saturated hydraulic conductivity (Ks) is crucial in environmental and engineering fields. However, the current direct measurement methods of Ks are time-consuming and labor-intensive. As an alternative method, many researchers have developed a series of pedotransfer functions (PTFs) that estimate Ks based on easily accessible soil properties. Unfortunately, most existing PTFs of Ks focus on temperate and tropical regions in the United States and Europe. There is a lack of research discussing the applicability of Ks models in subtropical areas. To resolve this issue, we conduct a study using 515 subtropical soil samples to test the performance of existing PTFs of Ks. The Ks values of investigated soils range from 1.4 × 10-4 to 290 cm h−1. Among the affecting factors, soil bulk density (ρb) and effective porosity (φe) are found to be the most important variables. Current PTFs considering soil pore structural property (i.e., φe) or soil texture solely are not effective in assessing Ks of subtropical soils. To address this limitation, we integrate soil pore structural and textural properties and develop a new PTF based on the Kozeny-Carman equation. The performance and reliability of the new PTF are evaluated using independent Ks datasets from various regions. The results show a significant positive correlation between the measured Ks and the predicted Ks from the new PTF for subtropical soils with an R2 of 0.69, an average RMSE in log10Ks (cm h−1) of 0.496, and a mean bias value of 0.070. Besides, the new PTF is found to perform as well as widely used machine learning tools.

Structural assessment and petrophysical evaluation of the pre-Cenomanian Nubian sandstone in the October Oil Field, central Gulf of Suez, Egypt

The low quality of the seismic resolution of the studied Cambrian Pre-Cenomanian formations, which rest directly on the basement in the October Field in the Gulf of Suez, requires study, and the structure pattern controlling these formations is uncertain. The poor quality of the seismic data resolution in the Gulf of Suez is due to the presence of thick sequences of evaporites represented by the South Gharib and Zeit formations. Therefore, the current study used seismic reflection data integrated with well-log data to define the structural-stratigraphic setting of the pre-Cretaceous Nubian reservoir sequence. The study aims at locating and delineating zones having excellent reservoir potential within the Nubian sequence horizons (Nubian Transition, main Nubian, Nubian marker-1, and Nubia marker-2, referred to as NT, MN, M1 and M2, respectively) through the integration of the 3D static modelling and the petrophysical parameters deduced from the well-log data processing. A detailed petrophysical analysis, based on the wireline logs of some wells, was performed to determine the lithological units using two types of cross plots (Neutron-Density and M-N plots), and the different petrophysical parameters that characterize the various Nubian horizons were also computed. 3D modelling was used to visualise the lateral and vertical changes of the reservoir characteristics. The seismic mapping reveals that the Nubian structure is controlled by an NW-SE trending (Clysmic trend) of an NE-plunging asymmetrical anticlinal feature unconformably resting on a basement horst. The main structure is affected by two major normal faults, which trend NW, andis cut by two smaller sub-parallel faults that disturb the core of the structure, which is unaffected by the easterly oriented faults of the Aqaba trend. The petrophysical analyses indicate that the Nubian sandstones have intervals of good reservoir quality, with a total net-pay thickness of about 500 m, net sand ratios (60–90 %), effective porosity (10–25 %), and hydrocarbon saturation (85%), which may encourage further drilling, especially in the southeast portion. The result of this study can be extended to the other Nubia sandstones resting on the basement complex in the Gulf of Suez.

Dispersion of silica-encapsulated DNA magnetic particles in a homogeneous sand tank

In this study, we focused on the 3D dispersion of colloids. To our knowledge, we were the first to do so. Thereto, we injected silica encapsulated DNA tagged superparamagnetic particles (SiDNAmag) in a homogeneous coarse grain sand tank. At four downstream locations, SiDNAmag concentrations were determined as a function of time. Longitudinal and transverse dispersivity values and associated uncertainties of SiDNAmag were determined using Monte Carlo modelling approach. The parameter associated uncertainties of hydraulic conductivity as well as of the effective porosity estimated from SiDNAmag breakthrough curves were statistically similar to those estimated from salt tracer breakthrough curves. Further, the SiDNAmag dispersivity uncertainty ranges were then statistically compared with the salt tracer (NaCl, and fluorescein) dispersivities. Our results indicated that time to rise, time of peak concentration and shape of the breakthrough curves of SiDNAmag were similar to those of the salt tracer breakthrough curves. Despite the size difference between the salt tracer molecules and SiDNAmag, size exclusion did not occur, probably due to the large pore throat diameter to SiDNAmag diameter ratio. The median longitudinal dispersivity (αL) of salt tracer and SiDNAmag were 4.9 and 5.8 × 10−4 m, respectively. The median ratio of horizontal and vertical transverse dispersivities to αL, (αTH /αL and αTV /αL, respectively), for salt tracer and SiDNAmag ranged between 0.52 and 0.56. Through the statistical tests, we concluded that the longitudinal and traverse dispersivities of SiDNAmag were not statistically significantly different from salt tracer in 3 dimensions and could be used to characterize the dispersive properties of the medium we used. Our work contributes to a better understanding of 3D dispersion of SiDNAmag in saturated porous media.

Tantalum oxide nanotube thin films: fabrication, optical properties, and porosity analysis

Tantalum oxide (Ta2O5) nanotubes exhibit remarkable properties and have garnered significant attention across diverse scientific disciplines and technological domains. This research article elucidates the successful preparation of amorphous, well-ordered Ta2O5 nanotubes through anodization in electrolytes incorporating hydrofluoric acid and concentrated sulfuric acid. The study comprehensively investigates the preparation methodology on the morphology of the nanotubes, elucidating their optical properties. Furthermore, the effective refractive index and porosity of the Ta2O5 nanotubes were quantitatively determined, offering valuable insights for the advanced utilization of Ta2O5 in several applications, encompassing battery electrode materials, memory resistors, and sensors.

Petrophysical Parameters and Electrofacies Models of the Itararé Group Applying Multi-Resolution Graph-Based Clustering Method, Paraná Basin

Volume shale (Vsh) and effective porosity (Φe) were calculated and partially applied as petrophysical input parameters to generate electrofacies models using the Multi-Resolution Graph-Based Clustering method in sedimentary successions of the Itararé Group. The petrophysical parameters and electrofacies models were determined from geophysical data from two wells located in the eastern portion of the Paraná Basin. The stratigraphic intervals in each well (analogues of hydrocarbon reservoirs) allowed petrophysical analysis and the determination of electrofacies models based on gamma ray profiles, apparent density and neutron porosity, together with lithological data. The petrophysical parameters were calculated by different procedures, and the effective porosity results were applied as input parameters for electrofacies modeling. The electrofacies models were correlated to lithological data and patterns of gamma ray profiles and apparent density, as well as different types of porosity. The generated models provide differences related to the type of porosity, the method applied to calculate the effective porosity and present probable relationships with the lithological units of the wells.

Petrophysical Evaluation of Arkoses Reservoirs Based on Well Logs and Plug Samples: A Case Study From Alagamar Formation, Southeastern Portion of Onshore Potiguar Basin, Brazil

The Potiguar Basin is a sedimentary basin located in northeastern Brazil. It covers about 48,000 km² and extends from onshore to offshore. The onshore basin is thought to have formed during the Late Cretaceous, as a result of the opening of the Equatorial South Atlantic Ocean, filled with a thick sequence of sedimentary rocks, including sandstones, shales, and limestones, which were deposited in a variety of processes, including marine, deltaic, and fluvial. The study area is in the southern portion of the basin and the reservoir is composed of arkose sandstones deposited by alluvial fan and fluvial systems of the Upanema Member of the Alagamar Formation, which belongs to the post-rift phase of the Potiguar Basin. Recently, new drilling campaigns revealed a reservoir heterogeneity in these deposits, which requested a new petrophysical approach. Using conventional well logs and petrophysical laboratory analysis of plug samples, this study evaluated the best way to calculate the effective porosity, and shale volume and to understand the stratigraphic controls in the distribution of these properties. Three reservoir zones were mapped: the basal one, Zone 3, has disconnected sand bodies, low porosity, and high shale content; Zone 2 has better petrophysical properties, lateral distribution, and connectivity between the fans and Zone 1 is the better reservoir zone with larger sand bodies, higher porosity values, and well-connected fans.

Laboratory Measurements and Estimates of the Biot Coefficient of a Pre-Salt Oil Field, Santos Basin

The Biot’s coefficient is an important parameter in geomechanical models of hydrocarbon reservoirs, with direct influence over the stress distribution in space and time along the production history. We conducted stress-strain experiments (quasi-static measurements) to measure the Biot coefficient of rock samples from an oil field in the Santos Basin. We found strong correlations between these quasi-static measurements and the estimates from dry rock ultrasonic elastic velocities (dynamic measurements). Additionally, we observed good correlations between the Biot’s coefficients and the effective porosity of the rocks, as well as with the acoustic impedances. These findings suggest that it is possible to derive poroelastic parameter logs of Biot’s coefficient in well locations, which can be used as input for geostatistical interpolation between wells. This would help in constructing more accurate reservoir geomechanical models and may even enable the generation of a three-dimensional distribution of the coefficient based on acoustic inversion of seismic data.

Geophysical evaluation and petrophysical assessment of the Abu Roash "F" Member: A probable unconventional oil reservoir in Heba Field, eastern Abu Gharadig Basin, Egypt

This study investigates the geophysical properties of the Abu Roash F Member (AR/F) as a potential unconventional oil reservoir in Heba Field, located in the eastern region of the Abu Gharadig Basin (Egypt). Analysis of seismic data reveals the influence of Late Cretaceous dextral wrenching tectonic activity, evidenced by the presence of ENE-WSW anticlinal folds and intersecting NW-SE as well as WNW-ESE extensional faults throughout the study area. This tectonic regime is believed to have played a significant role in the formation of micro-fractures within the AR/F carbonate, which can enhance the reservoir's potential by improving its permeability and porosity. Petrophysical assessment identifies favorable reservoir zones within specific depth intervals across multiple wells. These zones exhibit promising reservoir quality, characterized by low shale volume (below 0.20), which indicates a cleaner reservoir rock with less clay content. Additionally, the high total porosity (ranging from 0.20 to 0.25) and moderate effective porosity (ranging from 0.15 to 0.20) suggest that a substantial portion of the rock's pore space is available for storing hydrocarbons. The low water saturation (between 0.40 and 0.50) further supports the presence of hydrocarbons, as it indicates that the pores are not predominantly filled with water. Furthermore, the high hydrocarbon saturation (ranging from 0.50 to 0.60) confirms the significant presence of hydrocarbons within the reservoir. The quantitative assessment of these petrophysical properties across all analyzed wells further confirms the good reservoir quality and potential of the AR/F Member. The integration of seismic and petrophysical data provides a comprehensive understanding of the reservoir characteristics, highlighting the AR/F Member as a significant oil reservoir in the eastern border of the Abu Gharadig Basin, particularly in Heba Field. This study's findings complement the existing knowledge of oil-bearing formations in the region, suggesting that the AR/F Member could be a valuable addition to the basin's hydrocarbon resources. The results underscore the importance of further exploration and development of the AR/F Member to fully realize its potential as a major contributor to the area's oil production.

Development of petrophysical modeling based on effective porosity and phase permeabilities of reservoirs (Binagadi Oil Field as a case study)

Development of petrophysical modeling based on effective porosity and phase permeabilities of reservoirs (Binagadi Oil Field as a case study)

Przewidywanie dyfuzyjności termicznej na podstawie prędkości P-fal i oceny porowitości dla zbiorników piaskowca

Petrophysical heterogeneities of sandstone reservoirs which are generated by rock internal variability resounded to the magnitude of the rock thermal diffusivity. This is expected mostly to variation of rock density, porosity, reservoir temperature and its thermal conductivity. New methodology for calculating thermal diffusivity in a sandstone rock formation is intended and effectively employed some laboratory thermophysical measurements for sandstone reservoirs. The proposed petrophysical model establishes thermal diffusivity if both the effective porosity and acoustic (compressional) wave velocity of the rock are known. Some reliable petrophysical models (El Sayed, 2011 and Ahmed, 2019) concerned to both the Baharyia (Egypt) and Szolnok (Hungary) sandstone formations are used with only some modifications to build an innovative nomography. It permitted precise quantification and determination of the thermal diffusivity for both dry and saturated sandstone samples normalized to reservoir temperature (300K-1060 K). Verification of the proposed model is achieved with applying study cases of laboratory measured thermophysical properties (i.e., porosity, thermal diffusivity/or conductivity and longitudinal wave velocity) for different sandstone types, geological ages and geographic locations. A regression analysis of thermal diffusivity between laboratory measured and predicted data for dry (Ҡ-dry) rock samples yield a plausible coefficient of correlations as (R =0.73; 0.86 and 0.98) for three different sandstones obtained from Permo-Carboniferous in Germany (Aretz, 2016) and of dissimilar geologic age in Switzerland (Pimienta, 2018) respectively while, the average standard error equals 0.011. Then again, the laboratory measured and predicted thermal diffusivity (Ҡ-sat) of saturated samples display an appropriate coefficient of correlation (R = 0.76) and average standard error (0.0089).

Właściwości złoża jurajskiej formacji Khatatba: Pole naftowe Tut, Pustynia Północno-Zachodnia, Egipt

The Tut oil field is in the North-western part of the Western Desert. This work aims to study the reservoir characteristics, to evaluate the hydrocarbon potentiality of the Upper and Lower Safa Members based on the available subsurface data obtained from open-hole well log records of four wells distributed in the study area. Numerous isopach and lithofacies maps have been constructed. The petrophysical evaluation, in terms of determining reservoir net-pay thickness, shale content (Vsh), effective porosity (∅eff), water saturation (Sw) and hydrocarbon saturation (Sh), were estimated. The vertical and the lateral distribution of the reservoir characteristics, in the form of litho-saturation cross-plots, iso-parametric maps and lithologic-matrix cross-plots were constructed. Three hydrocarbon charged zones in the Khatatba Formation were defined and represented by the Upper Safa-Top, Upper Safa-Bottom and Lower Safa-Top. The upper most part of Upper Safa Member (Upper Safa-Top) reservoir represents an oil producing zone where it consists of shallow marine to alluvial sediments. The Lower most part of Upper Safa Member (Upper Safa-Bottom) reservoir represents gas producing zone where it consists of a thick alluvial sand body. Finally, the upper most part of Lower Safa Member (Lower Safa-Top) reservoir represents an oil-gas producing zone consisting of shallow marine sediments with high terrestrial input. The iso-parametric maps show that Northern and central parts of the study area are the most favorable parts for hydrocarbon accumulation due to the increase in net-pay thickness and average effective porosity and decrease in water saturation toward these parts.

A heat mining strategy for the potential Enhanced Geothermal System of the Acoculco Caldera Complex, Puebla (Mexico): A numerical approach based on Multiple Interacting Continua

As the world faces a transition to low-carbon electricity, energy markets have witnessed a fast expansion of Variable Renewable Energy, such as solar and wind power. In contrast, the installed capacity of geothermal electricity has increased with at a much lower rate. Continuous innovation is required to maintain geothermal electricity as a cost-competitive technology that helps building flexible power generation systems. Here we propose a heat mining setup for the promissory Enhanced Geothermal System (EGS) of the Acoculco caldera complex, which hosts a heat source in low permeability rocks. The conceptual model of the EGS reservoir consists of a fractured-porous layer between impermeable confining beds. An injection-production triplet is located in line with a fault plane that intersects the model area. Under the assumption of hydraulic stimulation to the fault zone, flow of the injection-production system restricts to a fracture network with secondary and variable permeability. Mass and heat transport is modeled following the Multiple Interacting Continua method with the software TOUGH2. We evaluate the performance of the heat mining system considering water and CO2 as working fluids for a given flow rate. We also evaluate the impact of fracture spacing in the reservoir performance. Results show that for a reservoir temperature of 300 °C, the CO2-based system experiences considerable adverse flow conditions that demands a higher pressure differential between the producer and injector (about 60 bar higher than the water-based reservoir). Likewise, the low heat capacity of CO2 imply a considerable limitation for heat mining. While for the water-based reservoir the cooling front extends throughout the entire reservoir at 30 yr of operation, for CO2 this happens in only about 60%. Additionally, the energy extracted per unit time in the water-based reservoir results more than twice the energy extracted with CO2. Finally, our numerical results show that fracture spacings in the range of 10 to 75 m behave similarly in terms of heat mining performance; decreasing the heat exchange area by increasing the fracture spacing from 10 to 75 m produces a minor impact under the assumption of high permeability fractures. Additional constrains for the fracture network, such as geometry, effective porosity and permeability of both fractures and rock matrix, have to be investigated in future research to better understand the possible performance of the production system.

A novel prediction model of oil-water relative permeability based on fractal theory in porous media

It is significant to accurately evaluate the relative permeability of oil–water two phase for multiphase seepage in porous media in low permeability and tight oil reservoir. However, stress sensitivity is an important characteristic for low permeability and tight oil reservoir. It is an effective way for fractal theory to describe the complexity and heterogeneity of the microstructure of porous media. To describe the relative permeability of oil–water two phase in porous media with complex and irregularity pores, a new relative permeability model oil–water two phases is proposed by the fractal theory and the stress sensitivity is taken into the established model in this paper. Meanwhile, the effects of effective stress, elastic modulus, porosity, maximum and minimum flow radius on oil–water relative permeability are analyzed. The new model is verified by comparing with the laboratory data and the results demonstrate that irreducible water and residual oil saturation have a negative correlation with effective stress. The relative permeability of the oil–water two-phase will shrink to the middle as the rise of effective stress, and the region of co-infiltration will decrease. The deformation quantity of porous media, irreducible water and residual oil saturation will increase as the elastic modulus decreases. The larger the maximum flow radius is, the lower the irreducible water saturation and residual oil saturation is. Both the porosity and the minimum flow radius have slight influences on the relative permeability of oil–water two-phase. The proposed relative permeability model can effectively predict the relative permeability of oil and water and help to describe and reveal the multiphase flow in porous media.

Study of Pore–Throat Structure in Tight Triassic Sandstone: A Case Study on the Late Triassic Yanchang Formation, Southwestern Ordos Basin, China

In order to better understand pore–throat structure characteristics, the coupling relationship between micropore–throat structure and macro reservoir quality and influencing factors caused by authigenic minerals were studied. Petrographic analyses, scanning electron microscopy (SEM), pressure-controlled mercury injection (PMI), nuclear magnetic resonance (NMR), and X-ray diffraction (XRD) were performed on a suite of tight reservoir samples from the Chang 8 Member of the Upper Triassic Yanchang Formation in the southwestern Ordos Basin, China. The results show that the pore–throat sizes obtained with the combination of PMI and NMR methods varied from nano- to microscale, revealing pore–throat sizes ranging from 0.001 μm to 70 μm, and showing that pore–throats with a radius larger than 1.0 μm are rare. Larger pore–throats with good connectivity (>rapex) account for a smaller part of the total pore volume, ranging from approximately 7.58% to 38.90% with an average of 22.77%, but account for more than 80% of contributions to permeability. The effective movable fluid porosity (φemp) measured by NMR, ranging from approximately 0.10% to 7.07% with an average of 2.56%, had a positive contribution to permeability. The contents of chlorite occurrence state, other than illite, are beneficial to pore–throat preservation. A new reservoir evaluation scheme of the Chang 8 reservoir is established. These research results provide a theoretical basis for the evaluation and development of tight sandstone oil and gas exploration.

Focused reservoir characterization: analysis of selected sand units using well log and 3-D seismic data in 'Kukih' field, Onshore Niger Delta, Nigeria

This study focuses on the comprehensive reservoir characterization of the ‘Kukih’ Field within the onshore northeastern Niger Delta region, Nigeria. The absence of its detailed description with delineated reservoir properties, lateral continuity, and their use to identify potential reservoir quality and heterogeneity necessitated this study. Integrating well log and 3D seismic data, the investigation aims to elucidate reservoir properties, lithofacies, and depositional environments to unravel hydrocarbon potential. The geological setting, encompassing the Agbada Formation of Early and Middle Miocene age, is scrutinized through detailed geologic analysis. Petrophysical evaluation of four well logs (Kukih-1, Kukih-2, Kukih-3, and Kukih-4) facilitated the determination of key parameters such as shale volume, effective porosity, and water saturation. Seismic interpretation further enriched the structural characterization of the field. Results showcase three predominant reservoir sands (A, B, and C) with distinct lithofacies and thickness variations. Effective porosity ranges from Fair to Excellent, with permeability exhibiting high values for hydrocarbon reservoir potential. Water saturation trends, lithofacies distributions, and structural features were illuminated through iso-parametric maps and seismic analyses. Depositional environments were inferred through facies analysis, revealing the presence of funnel-, cylinder-, and bell-shaped successions that hint at intricate marine sedimentary processes. Challenges owing to limited core data were acknowledged, and the integration of methodologies emerged as a pivotal strategy for enhanced reservoir understanding. This study underscores the ‘Kukih’ Field's hydrocarbon potential, accentuating the significance of multidisciplinary approaches in deciphering complex reservoir systems. In light of the petrophysical analysis derived from the well logs and the identification of structural highs through the structural maps, this study recommends the drilling of unexplored zones exhibiting promising structural characteristics.

Rock Mineral Volume Inversion Using Statistical and Machine Learning Algorithms for Enhanced Geothermal Systems in Upper Rhine Graben, Eastern France

AbstractAccurately determining the mineralogical composition of rocks is essential for precise assessments of key petrophysical properties like effective porosity, water saturation, clay volume, and permeability. Mineral volume inversion is particularly critical in geological contexts characterized by heterogeneity, such as in the Upper Rhine Graben (URG), where both carbonate and siliciclastic formations are prevalent. The estimation of mineral volumes poses challenges that involve both linear and nonlinear relationships associated with geophysical data. To address this complexity, our methodology strategically integrates the robust insights from standard statistical approaches with three machine learning (ML) algorithms: multi‐layer perceptron, random forest regression, and gradient boosting regression. Furthermore, we propose a new hybrid ensemble model that incorporates a weighted average of multiple ML approaches to predict mineral composition within the Muschelkalk and Buntsandstein formations of the URG. ML techniques for mineral composition prediction in these formations exhibit robust predictive performance. The predicted mineral volumes align closely with quantitative estimates derived from X‐ray diffraction analysis. Additionally, they are in good qualitative agreement with mineral descriptions obtained from cores and cuttings of the Muschelkalk and Buntsandstein formations.

Petrophysical evaluation based on three-stream convolutional neural networks in the Berkine Basin, Algeria

Petrophysical evaluation is a key stage before formation test in exploration field, it allows the identification of the best plays in term of effective porosity, shale volume and hydrocarbon saturation. This paper introduces an innovative approach to petrophysical evaluation by leveraging deep learning techniques, our scheme is based on three streams, in each stream we predict a petrophysical parameter (Volume of shale, Effective Porosity and water saturation), each stream represents a convolutional neural network model that has been trained using traditional wireline logging data from the Silurien argilo-greseux reservoir units in the Berkine Basin, Algeria. experimental results show that our proposed method achieves stat-of-the-art predictions by giving correlated results in comparison against conventional analysis methods (calculated Shale Volume, Porosity and water saturation), furthermore assessment of test data shows also that our method gives good prediction in thin beds reservoirs and offers the ability to detect low resistivity pays. Because our method is based on Convolutional neural network models, it is fast and allows the petrophysical parameters prediction in real time.