Range Of Porosity Values Research Articles

Sedimentary characteristics and geological significance of a mixed-process delta for petroleum exploration in the Zhuhai formation of the Baiyun Depression, Pearl River Mouth Basin, China

The Zhuhai Formation in the Baiyun Depression of the Pearl River Mouth Basin in the northern South China Sea is a marine delta influenced by multiple hydrodynamic forces, including rivers, waves, and tides, resulting in a mixed-process delta. As a result of the combined effects of these forces, the distribution patterns and reservoir structures in the sandstone formations of the Zhuhai Formation are extremely complex. This paper provides a detailed description of the coring section of the Zhuhai Formation drilled in the Baiyun Depression, focusing on the lithology, sedimentary structure, special containers, and depositional dynamics of the coring section. It also summarizes the characteristics of a hybrid power delta controlled by rivers, waves, and tides, and explores the geological significance of this mixed-process delta for oil and gas exploration. The study reveals that sedimentation controlled by rivers primarily consists of medium-to-fine sandstones with interbedded cross-bedding and parallel bedding. Scour-fill structures and a bell or box-shaped natural gamma ray logging curve (GR) are also observed. Seismic reflection exhibits strong amplitude and high continuity. Wave-controlled sedimentation, on the other hand, predominantly consists of silt and fine sandstones with scouring, wave-formed cross-bedding, abundant bioturbation, and a serrated and funnel-shaped GR curve. Seismic reflection shows medium amplitude and high continuity. Tidally-controlled deposits are characterized by thin interbeds of mudstone, siltstone, and fine sandstone, as well as vein laminations, undulating composite laminations, lenticular laminations, and biclastic layers. The GR curves for tidally-controlled deposits are sharp or jagged with funnel shapes, and seismic reflections exhibit medium amplitude and continuity. The hydrodynamic features controlling sedimentation during the depositional period of the Zhuhai Formation in the Baiyun Depression exhibit evident zonation on a planar scale, influenced by sedimentary paleogeography and sea-level changes. River control is predominant in the northern Zhuhai Formation, with local wave influence and minimal tidal influence. In the southern part, tidal action becomes increasingly important. In terms of reservoir properties, wave-controlled reservoirs display significantly better porosity and permeability compared to tidally-controlled and river-controlled reservoirs. Tidally-controlled reservoirs exhibit high heterogeneity with a wide range of porosity and permeability values. The varying influences of different hydrodynamic drivers in different locations have led to significant variations in the size, morphology, and physical properties of sand bodies within the marine delta sediments of the Zhuhai Formation in the Baiyun Depression. Thus, the type and intensity of sedimentary hydrodynamics become the primary controlling factors for the development of high-quality reservoirs.

Comparison of geomechanical upscaling methods for prediction of elastic modulus of heterogeneous media

Geomechanical properties of rocks are essential for understanding their elastic behavior. These parameters find their applications in various fields such as petroleum engineering, and geological storage sites, of nuclear waste and carbon dioxide and other geotechnical operations. There are several methods to obtain these parameters, including experimental methods, mathematical upscaling, and numerical simulation while experimental approaches are more trusted. The aim of this study is to estimate Young's modulus of a shale sample from several major upscaling mathematical methods and compare the results to polyaxial compressive strength test and nanoindentation measurements on the same piece of sample. To achieve this, five major theoretical upscaling models, including DEM, MT, SCA, KTF, and DM, have been utilized to calculate the Young's modulus based on constituent components of the sample that was obtained from routine XRD and geochemical analysis. The calculations for each of the five methods were performed in two scenarios: without incorporating the organic matter in the model and with it, in a range of porosity values while input parameters for each constituent component were found from the literature. Young's modulus with organic materials following the upscaling schemes was in the range of 24.0661 [GPa] to 27.0001 [GPa]. Likewise, excluding the organic substances Young's modulus was calculated 25.1784 [GPa] and 29.1394 [GPa], as the smallest and largest values, respectively. These values were compared to the Young's modulus obtained from the nanoindentation (34.15 GPa) and polyaxial test (24.36 GPa). The Young's modulus decreases of approximately 7% with considering organic matter around 2.45% and decrease of less than 5% with variation of 1% porosity. Based on the results, it was concluded that upscaling methods overall provide results in an acceptable range while they are more cost-effective and time-efficient when compared to expensive and time-consuming experimental approaches and can replace them. Furthermore, the use of upscaling methods reduces the need for destructive testing and also eliminates the requirement for expensive equipment with limited access to proper size of the samples and required preparations that should be followed. However, the lithology of the sample and presence of certain type of pore spaces and fractures should not be taken lightly in this process.

Evaluation of shale oil and gas plays - Part I: Shale reservoir property modelling of the North Sea Kimmeridge Clay Formation

The Kimmeridge Clay Formation (KCF) forms the source rock for most conventional hydrocarbon accumulations within the UK North Sea. However, only a few previous studies have analyzed the potential of the KCF for unconventional resources (i.e., shale oil and gas).Here, we use machine learning techniques combined with established rock property equations to generate geochemical, petrophysical and geomechanical logs for 16 wells within Quadrant 15 of the Outer Moray Firth, UK North Sea. The neural network models used to generate geochemical logs are trained using the Levenberg-Marquardt backpropagation algorithm. The generated well logs and new KCF depth maps, constrained by an existing Base Cretaceous Unconformity (BCU) map of the UK North Sea and well top information from 48 wells, are used for 3D geostatistical modelling of KCF properties across the area. The resulting KCF property maps allow us to assess the shale oil and gas play potential across the region.Our results suggest good organic richness and hydrocarbon yield potential for the KCF within the study area, with up to 9 wt% original total organic carbon (TOCo), 48 mg/g original hydrocarbon yield (S2o), and 607 mg/gTOC original hydrogen index (HIo). Modelled total porosity values range between 2 and 13%, and brittleness indices lie between 25 and 65%, within the range reported for proven shale oil and gas plays.A sweet spot map, created by integrating our modelled KCF properties, indicates prospective areas for shale oil and gas exploitation within the central Witch Ground Graben, and to a lesser extent areas of the Piper Shelf and Claymore-Tartan Ridge. These areas show good potential based on all investigated properties, with respect to industry standards.

Subsurface Thermophysical Properties of Europa’s Leading and Trailing Hemispheres as Revealed by ALMA

We present best-fit values of porosity—and the corresponding effective thermal inertiae—determined from three different depths in Europa’s near-subsurface (∼1–20 cm). The porosity of the upper ∼20 cm of Europa’s subsurface varies between 75% and 50% (Γeff ≈ 50–140 J m−2 K−1 s−1/2) on the leading hemisphere and 50%–40% (Γeff ≈ 140–180 J m−2 K−1 s−1/2) on the trailing hemisphere. Residual maps produced by comparison with these models reveal thermally anomalous features that cannot be reproduced by globally homogeneous porosity models. These regions are compared to Europa’s surface terrain and known compositional variations. We find that some instances of warm thermal anomalies are co-located with known geographical or compositional features on both the leading and trailing hemisphere; cool temperature anomalies are well correlated with surfaces previously observed to contain pure, crystalline water ice and the expansive rays of Pwyll crater. Anomalous regions correspond to locations with subsurface properties different from those of our best-fit models, such as potentially elevated thermal inertia, decreased emissivity, or more porous regolith. We also find that ALMA observations at ∼3 mm sound below the thermal skin depth of Europa (∼10–15 cm) for a range of porosity values, and thus do not exhibit features indicative of diurnal variability or residuals similar to other frequency bands. Future observations of Europa at higher angular resolution may reveal additional locations of variable subsurface thermophysical properties, while those at other wavelengths will inform our understanding of the regolith compaction length and the effects of external processes on the shallow subsurface.

Re-evaluation of the Hydrocarbon Potential of the Scarborough Field, Offshore Northern Carnarvon Basin, Australia.

This study examines the detailed basin analysis and re-evaluation of the hydrocarbon potential of the Scarborough Field in the Northern Carnarvon Basin, offshore Australia, aiming to enhance energy reserves. The research integrates extensive datasets, including a 3-D seismic reflection volume, fifty-two 2-D seismic lines, well logs from six wells, checkshot surveys, and surface geologic maps. The Northern Carnarvon Basin, a significant hydrocarbon reserve in Australia, has experienced a multi-phase extensional history and exhibits a complex stratigraphy linked to six tectonic phases. The pressing need for increased energy reserves necessitates revisiting old hydrocarbon fields to boost their production capacity using integrated methods. Well-log interpretation and correlation have revealed the lateral extents of petroleum system elements. The stratigraphic analysis identified three sequences and associated system tracts using the Depositional Sequence Model IV. Structural framework interpretation highlighted faults as migration pathways and hydrocarbon traps. Time and depth structure maps were produced to identify leads and prospects. Four leads and three prospects were pinpointed using RMS amplitude surfaces. Porosity values range from 20% to 29%, with hydrocarbon saturation between 51% and 65%. Volumetric assessment indicates that NAU Deep-1 contains 10.6 bcf, NAU Deep-2 holds 4.24 tcf, and NAU Deep-3 has 6.22 tcf of gas. These significant gas volumes highlight potential for future exploration and development in the Scarborough sedimentary infill.

Evaluation of Carbonate Reservoir with Integration of Petrophysical Analysis and Seismic Impedance Inversion in Banggai Basin, Sulawesi

Banggai Basin is controlled by the collision between Banggai-Sula micro-continent and East Sulawesi ophiolite belt, forming a thrust-sheet anticline structure that has potential to trap hydrocarbon. The Siotu-1 well was drilled right into the thrust-sheet anticline structure targeting Miocene carbonate platform layer. The same structure has proven to be an oil trap at the Tiaka oilfield which is located adjacent to the Siotu-1 well. This study aims to evaluate the presence of hydrocarbon in the Siotu-1 well with characterization of the Miocene carbonate reservoir. It is carried out by integrating petrophysical analysis from the Siotu-1 well log data and 2D seismic impedance inversion of the Tarib-1 line. Five reservoir zones have shale content values range of 21.91-37.53%, effective porosity values range of 9.7-14.62%, water saturation values range of 88.5-98.27%, and permeability values range of 2.53-8.16 mD. The results of the porosity calculation are validated by the model of seismic inversion where the reservoir zone with an acoustic impedance in the range of 7600-13450 ((m/s)/(g/cc)) is a carbonate layer with fair to excellent porosity (10 to> 25%) and reservoir zone with acoustic impedance values range of 13450-16200 ((m/s)/(g/cc)) as carbonate layer with poor porosity (< 10%). The net pay zone in reservoir zone 4 with a thickness of 4.5 feet and a net-to-gross of 0.006 are shown as the lumping result. It is concluded that Miocene carbonate reservoir in the Siotu-1 well met the criteria as a good reservoir rock but insignificant of hydrocarbon potential for further development.

Characterization of proven Late Cretaceous Reservoir rocks in the Gulf of Gabes: Integrated case study

Microstructural features control the petrophysical properties of rocks. Of these, pore size is particularly sensitive when non-wetting fluids saturate the reservoir. The pore networks and physical properties (helium, water and mercury saturation porosity, bulk density, nitrogen permeability, P-wave velocity and thermal conductivity) of different rock types from a productive Upper Cretaceous (Coniacian) reservoir in the tunisian offshore are measured on hydrocarbon-washed samples. The facies sampled of Douleb Member are wackestone, packstone and grainstone textures as well as dolostone, dolomitized packstone and anhydrite textures. Based mainly on the results obtained by mercury injection, the porous facies of the Coniacian Douleb Member are characterized by a complex pore system with a large morphological and pore size variability in the rock. Porosity values range from 0.3 to 23.6%, bulk densities vary from 2.05 to 2.92 g.cm−3. The permeability is variable from 3760 mD to values below 0.01 mD (measurement limit of the device). P-wave propagation velocity values range from 2060 to 6084 m.s−1 and thermal conductivity varies from 1.43 to 3.77 W.m−1.K−1. The oil-impregnated facies with the best petrophysical characteristics are mainly the rudist-rich limestones and dolomites of the first unit (U1) of the Douleb Member. The well-sorted grainstones with small rudist debris and peloids have the best reservoir qualities. Porosity is the first order characteristic that controls petrophysical properties. The variability of permeability values around this first-order relationship is attributed to variations in the size of the pore access thresholds and connectivity. The variability in velocities is due to the shape of the voids, while the variability in thermal conductivity measurements is due to the nature of the contacts between the grains.

The rock typing of complex clastic formation by means of computed tomography and nuclear magnetic resonance

This study provides a new rock-typing approach for low-resistive and low-permeable clastic rocks. The approach includes integrated interpretation of routine core analysis data with microstructural characteristics, acquired from computed tomography (CT) and nuclear-magnetic resonance (NMR) data. The studied formation comprises siltstones in its bottom, which are replaced by sandstones in its top. Sandstones form the main part of the oil reservoir, whereas siltstones were originally considered as water-saturated. The reserves calculation was performed based on a single Archie equation for the whole formation. Despite on apparent water saturation and low permeability of the siltstones, incidental perforation showed considerable oil inflow from them as well. In order to delineate missed productive intervals within the low-resistive siltstones, we had to develop a new rock-typing approach, acknowledging rock multimineral composition, diversity of microstructures, a wide range of porosity, permeability, and residual water saturation values. Designed laboratory program included porosity, permeability, electrical resistivity measurements, capillary, NMR and CT tests. The experiments were performed on the same core samples that enabled reliable correlation between measured parameters. The joint interpretation of flow zone indicator, calculated as a function of porosity and residual water saturation, together with the results of petrophysical and microstructural measurements allowed reliable rock-typing of the clastic formation. It will serve as a petrophysical basis for identification of the missed productive intervals. The developed laboratory program and rock-typing algorithm can be implemented in other oilfields.

Petrophysical Characterization of Shaly Sand Reservoirs in Well UK-05 Eastern Niger Delta Basin, Nigeria

A petrophysical evaluation of Well UK-05 in the eastern Niger Delta Basin was carried out in order to determine reservoir zones, their porosity, permeability, fluid saturation and the effect of shaliness on the petrophysical parameters. Using interactive petrophysics software version 3.5, twenty five (25) reservoir zones were identified. The porosity values range from 15.77- 4.66% and permeability from 2.76-546.54 mD. The Archie’s, Simandoux, Dual-porosity, Waxman and Smith, and the Indonesian models were used to determine the fluid saturation. The water and hydrocarbon saturation values using the Indonesian model are 21.67-50.49% and 49.51-78.33% respectively. They slightly differ from the ones obtained using Simandoux, Dual Water and Waxman and Smith model (20.72-49.88% and 50.12- 9.22%, 18.26-50.49% and 49.51-81.74%, 14.67-48.26% and 51.74-5.33% for water and hydrocarbon saturation respectively). The interpreted lithology shows that the formation penetrated by the Well UK-05 is dominated by alternating sands and shales with the sand being the dominant lithology. These lithostratigraphic characteristics correspond to those of the parallic Agbada Formation. The effective porosity values obtained range from 14.93 to 34.66%, which are lower than 0.013% to 94.08% obtained by other authors since they did not take into consideration the effect of shaliness. This shows that the more the shale volume, the higher the uncertainty of actual porosity of the reservoir.

Generalized correlation for effective thermal conductivity of high porosity architectured materials and metal foams

This paper presents a numerical study on the effective thermal conductivity (keff) of architectured materials typically realized through additive manufacturing. Four different unit cell topologies- Cube, Octet, Face-diagonal Cube, and Tetrakaidecahedron, were simulated for a range of porosity values, and both solid- and fluid-phase thermal conductivities. Numerically predicted keff values were validated against the in-house experiments carried out on single-cell thick 5 × 5 unit cell arrangement samples. These simulations led to a correlation for keff as a function of lattice porosity and thermal conductivities of solid- and fluid-phase materials. For the solid-to-fluid thermal conductivity ratio (ks/kf) greater than 300, the keff showed dependence on only the solid thermal conductivity for any given porosity and unit cell topology. The proposed correlation for the keff of architectured materials is applicable to all the four unit cell topologies with porosities > 0.8, and ks/kf ranging from 102 to 104. For these parameters, the correlation can also predict the keff of high-porosity metal foams obtained via foaming process with an accuracy of ±10%.

Well Log Interpretation and Petrophysical Modeling to Evaluate Zubair Reservoir in North-Rumaila Oil Field

This study uses well log interpretation and petrophysical modeling, which is one of the most influential tools for the evaluation of Zubair Reservoir in the X Oil Field. Understanding reservoir parameters and boosting output by picking the optimal location for future drilling candidates will be helped by these interpretations and modeling. 3D seismic and well log data were used to create and describe a petrophysical model in this investigation. Each parameter was upscaled when interpreting well logs and calculating petrophysical characteristics. The petrophysical model was created using geostatistical approaches such as Gaussian simulation, variogram, and Monte Carlo simulation. Techlog, Petrel, and HRS Software were used in this study. As a result, we analyzed porosity, shale volume, and water saturation for four wells named A, B, C, and C using a set of commercial software and applying the different well logs like; gamma-ray (gr) log, spontaneous potential log, porosity logs (Density Log, Neutron Log, and Sonic Log), and resistivity log. The range of porosity values is 0.23 to 0.30, the water saturation is around 10% in the crest and 60% in the flank, and Vsh is interbedded with sand and the value is decreasing 25% in the clean sand bed. This formation is characterized by clean sand and is interbedded with a sharp boundary. The sand in the main pay is characterized by homogeneous and uniform porosity patterns. The homogeneous nature of the sand leads to uniform saturation of water to fill this entire sand unit with oil and the absence of a transition zone.

Seismic Interpretation and Petrophysical Analysis for Evaluation of Ataga Field, Onshore Niger Delta, Nigeria

The majority of geophysical survey in hydrocarbon exploration and production sector is driven by the ability to describe reservoirs. This research is aimed at describing the interpretation and petrophysical analysis of the reservoirs in Ataga field Niger Delta using a combination of seismic and well-log data. The Ataga Field in the Niger Delta was subjected to 3-D seismic interpretation and petrophysical study to perform comprehensive structural interpretation, prospect evaluation, and volumetric calculation. Two reservoir windows “1” and “2” were identified and correlated from four wells ATA 10, ATA 11, ATA 5 and ATA 7. Detailed evaluation was done on well ATA 11 since it is the only well that has sufficient data for both qualitative and quantitative interpretation. Structural interpretation for inline 5731 revealed fifteen faults on the seismic vertical section through ATA 11, most of which are antithetic faults while the rest are synthetic faults. Top and base of each reservoir window was delineated from the well. Result of the petrophysical assessment of reservoir A, B and C for ATA 11 revealed that the porosity values range from (24 -29) % which are indicative of very good to excellent porosity value according to Rider (1996). While the permeability values range from (1887-2582) mD were obtained from the three reservioir A, B and C of ATA 11 which depict very good to excellent reservoir units. Since, .all of the wells were discovered to have hydrocarbon-bearing reservoir formations (sandstones), the integration of structural interpretation and well logs have successfully revealed that the reservoirs are mostly oil-bearing zones.

Prediction of pore-scale-property dependent natural convection in porous media at high Rayleigh numbers

Natural convection in porous media has received increasing attention in recent years due to its significance in engineering applications. This process is traditionally analyzed by the solution of the classical Darcy-Oberbeck-Boussinesq (DOB) equations. According to the DOB equations, natural convection in porous media is exclusively dependent on the Rayleigh-Darcy number, Ra, while the Sherwood number, Sh, has a linear relationship with Ra at high Rayleigh numbers. However, these predictions conflict with experimental observations. In this study, we have performed a pore-scale resolved direct numerical simulation (DNS) study of natural convection in periodic porous media composed of two-dimensional square and circular obstacles. Based on our analysis, a new correlation of Sh for large Rayleigh numbers (Ra≥1000), low Darcy numbers Da, and high Schmidt numbers Sc (Da/Sc≤2×10−8) has been proposed, expressed as Sh=aRa1−0.2φ2+1, where a=0.011±0.002 is a pore-scale geometric parameter. The new correlation has been validated over a wide range of Rayleigh numbers, porosity values, and pore-scale geometries. Our DNS results also show that, with a decrease of porosity, it becomes more difficult for mega-plumes with low wavenumbers to enter the boundary layer. Low wavenumber motions decay much faster with a decrease of Da than the pore-scale motions near the wall. The volume-averaged dissipation rate nondimensionalized using the pore size εˆi has the scaling law εˆi∼Da in the internal region and εˆi∼Da1/2 in the near-wall region. We expect that these characteristics obtained from DNS also apply to natural convection in porous media with much lower Darcy numbers.

Permeability anisotropy in model porous media formed by periodic cubic structures

One way to model porous media is to use periodic structures. The advantage of this approach is the need to describe the fluid flow in the volume of one pore (cell). The flows of a viscous fluid in periodic channel models of porous media formed by structures of three types — cubic simple (CS), cubic body-centered (BCC), and cubic face-centered (FCC) are considered. These structures make it possible to simulate porous media in a wide range of porosity values (1 ÷ 48%). In the selected structures, three special flow directions are distinguished — along the edge of the cube, along the diagonal of the square (the base of the cube), along the diagonal of the cube. For the chosen directions, the fluid flow was calculated over the entire range of the dimensionless parameter α — the degree of intersection of the spheres, which is a model parameter that characterizes the microheterogeneities of the porous medium and makes it easy to reproduce the geometry of the pore space in the numerical solution of the Navier-Stokes equations in direct hydrodynamic modeling. Based on the results of calculations based on the Darcy equation, the permeability coefficients for the three main flow directions were determined and an analysis was carried out on the permeability anisotropy in the selected structures. In a simple cubic structure, the greatest permeability is achieved in the 2nd direction (along the diagonal of the base of the cube), the smallest — along the main direction (along the edge of the cube). In a cubic body-centered structure, the highest permeability is achieved in the 3rd direction (along the diagonal of the cube), the lowest — along the 2nd direction (along the diagonal of the base of the cube). In a cubic face-centered structure, the highest permeability is achieved in the 2nd direction (along the diagonal of the base of the cube), the smallest — along the 3rd direction (along the diagonal of the cube).

Multi-objective optimization and performance assessment of microchannel heat sinks with micro pin-fins

In this study, laminar, steady-state microchannel flow and conjugate heat transfer in a microchannel heat sink (MCHS) with micro pin-fins were investigated numerically. Computational Fluid Dynamics (CFD) simulations were performed with ANSYS Fluent for heat and fluid flow in MCHSs with circular-, square- and diamond-shaped micro pin-fins of the same hydraulic diameter. Arrangements of micro pin-fins in the MCHS were optimized for each shape using a multi-objective genetic algorithm (MOGA) method called Non-dominated Sorting Genetic Algorithm (NSGA-II). The fluid entered the microchannel at channel Reynolds numbers ranging from 100 to 350, corresponding to circular- and square-shaped pin-fin Reynolds numbers ranging from 20 to 110 and diamond-shaped pin-fin Reynolds numbers ranging from 20 to 190. In all simulations, uniform heat flux of 60 W/cm2 was applied from the bottom surface of substrate. As the cooling fluid, water with temperature-dependent variable viscosity was assigned in the fluid domain and copper with constant thermophysical properties was considered for the entire solid domain. Design variables were selected in order to represent both the pin-fin arrangement and flow-characteristics: porosity number and pin-fin Reynolds number, respectively. As objective functions, pressure drop ratio was defined as the hydrodynamic performance indicator and the Nusselt number was chosen to represent the thermal performance. To represent the trade-off between two objective functions, optimization was conducted after a systematic parametric study and pareto-fronts were obtained. Optimized solutions of each pin-fin shape showed that square-shaped pin-fin was unfavorable compared with the performance of other shapes of pin-fins. Among all configurations, diamond-shaped pin-fins significantly enhanced heat transfer at an increased pressure drop ratio. Depending on the pin-fin shape, optimal configurations emerged over a wide range of porosity values mostly at the upper limit of the pin-fin Reynolds number, with average Nusselt numbers varying between 3 and 12 and corresponding pressure drop ratios varying between 1 and 12.

Analysis of Microstructure Evolution and Mechanical Properties during Compression of Open-Cell Ni-Foams with Hollow Struts Using Micro-CT and FEM.

Based on electron backscatter diffraction (EBSD), hollow structures of Ni foam struts fabricated by electroplating on a chemically removable template were observed. Three-dimensional (3D) pore structures of Ni foams were also obtained using X-ray computed tomography (CT), and microstructural features such as porosity, pore size and strut thickness were statistically quantified. Evolution of microstructure and mechanical properties during ex situ compression of open-cell Ni-foams was investigated based on X-ray CT, and experimental results were compared with predictions by the finite element method (FEM). 3D microstructures obtained by X-ray CT revealed that the stress drop started with the buckling of struts at the center of the Ni-foams. The flow stress increased after the buckling of the struts spreads to most of the regions. For effective simulation of the compressive deformation and determination of the microstructural evolution, small domains of interest were selected from the entire set of observed 3D microstructures based on X-ray CT, and struts of Ni foams with a hollow structure were simplified with relevant thin-solid struts. Numerical 3D modeling comprehensively disclosed that compression caused the transverse buckling of the struts, with the bending and buckling of struts thus reducing the stress. Thickness variation of the struts causes a change in the porosity of Ni-foams without a change in pore shape or connectivity. The overall range of strut thickness was from 59 to 133 m, and the range of porosity values was from 80% to 93.7%. A stress drop was predicted with a decrease in the strut thickness or an increase in the porosity, as measured experimentally. It was also found that the stress drop contributed to an increase in the calculated energy absorption efficiency.

Carbonate strength classification based on depositional textures and fossil content of the Lower Eocene Drunka Formation, Assiut Area, central Egypt

The present study reports petrographic and physico-mechanical analyses conducted on the lower Drunka Formation in the Assiut Area of Central Egypt. The study investigated the percentage of carbonate content and percentage of allochems “Ach” and their impact on the petrophysical features using correlation and multivariate regression analyses. This study analyzes the petrophysical characterization of Drunka Formation rocks and the effect of fossil content on them. The carbonate rock samples derived from the lower Drunka Formation were studied to evaluate the compressive strength , dry and saturated unit weight, porosity, and acoustic wave velocities. The petrographic examination of the rock samples was conducted to understand the facies characteristics, size and percentage of grains, matrix type and extent of diagenesis . Various microfacies associations were also detected within the examined samples, such as lime-mudstone, echinoidal bioclastic wackestones, nummulitic/miliolid wackestones, bioclastic peiodal packstone, echinoidal packstone and nummulitic grainstone . Petrophysical analyses displayed a wide range of porosity and dry bulk density values from 1.3 to 2.75% and 2.31–2.48 g/cm 3 , respectively. The wet bulk density and grain densities are between 2.33˗2.50 and 2.35˗ 2.57 g/cm 3 , respectively. The dry ultrasonic wave velocity “V p” was observed between 2926 and 5549 m/s, whereas the saturated ultrasonic wave velocity “V p “was estimated between 3067 and 5875 m/s. The Unconfined Compressive Strength (UCS) of the tested samples was 22 ≤ UCS ≤ 82 MPa while the slake durability index was recorded as 94.37 ≤ SDI ≤ 98.7%. The Brazilian test indices characterized the studied rock samples as highly porous rocks and showed the values of 1.47 ≤ Brazilian ≤ 5.13 MPa. Finally, for all tested facies, the Böhme test data have a minimum, maximum, and an average of 12.98, 25.95, and 19.04 cm 3 /50 cm 2, respectively. The study's findings showed that, except for the mineral grain scale, the physico-mechanical properties are highly dependent on the petrographic characteristics. The study also revealed that the Ach% and the rock's carbonate content significantly affect the rock's petrophysical and mechanical properties under investigation. The mechanical properties such as UCS, tensile and point load test. increase with increasing carbonate content and decreasing with increasing Ach% of the rock. This paper presents an extensive dataset of physical parameters of a carbonate formation in Egypt; many empirical relationships are presented for predicting mechanical properties. This provides site-specific predictive value; the relationships can be used for all carbonate rocks worldwide with broader international significance. • Classification of strength from texture is proposed based on fossil and carbonate content. • This study analyzes the petrophysical characterization of Drunka Formation rocks and the effect of fossil content on them. • This paper introduces a new strength classification of carbonate rocks based on allochems and carbonate content. • The depositional texture of carbonate rocks has a significant impact on variations of physico-mechanical properties of rocks. • Diagenesis has a remarkable effect on rock strength.

Specific surface area: A reliable predictor of creep and stress relaxation in gas shales

In recent years, short-term creep parameters determined in the laboratory from cylindrical gas shale samples subjected to triaxial (in-situ) stress conditions have been used successfully to infer long-term deformation and stress relaxation at the reservoir scale across geologic time scales. Due to the viscoelastic formalism, both the laboratory creep response and field-scale stress relaxation can be modeled with power law functions of time involving the elastic compliance of the shale B, the time-dependence exponent n, and the amount of total strain ∊. Gas shales often exhibit a high specific surface area associated with their high content in clay minerals and/or total organic carbon (TOC). The low-pressure nitrogen adsorption technique can be used advantageously to estimate specific surface area (SN2); i.e., it is a relatively fast and cost-effective measurement conducted on powdered samples of shale material. A robust global empirical correlation between gas shale creep parameters and SN2 emerges from the analysis of laboratory data collected from multiple gas shale formations in Australia (the prospective Goldwyer Formation) and the United States (Barnett, Haynesville, and Eagle Ford formations), and spanning a broad range of clay content, organic matter, maturity, and porosity values. This data set also shows that the summed fractions of clay minerals, TOC, and porosity, the so-called weak phase fraction, correlates nearly as well with primary creep parameters. The weak phase fraction can also be estimated from faster and more cost-effective measurements or from well logs. To evaluate its predictive capacity, the key correlation between SN2 and creep parameters is used in a case study to predict the magnitude of present-day least principal stress Shmin across six depth intervals/lithologic layers in a prolific unconventional shale formation in the northeastern United States. Several Shmin measurements are available for verification, and our approach successfully captures the observed layered variation of stress with depth.

Petrophysical Analysis of ‘Bright’ Field, Onshore Niger Delta

Petrophysical analysis is key to the success of any oil exploration and exploitation work and this task requires evaluation of the reservoir parameters in order to enhance accurate estimation of the volume of oil in place. This research work involves the use of suite of well logs from 4-wells to carry out the petrophysical analysis of ‘Bright’ Field Niger Delta. The approach used includes lithology identification, reservoir delineation and estimation of reservoir parameters. Two sand bodies were mapped across the entire field showing their geometry and lateral continuity, gamma ray and resistivity logs were used to delineate the reservoirs prior to correlation and relevant equations were used to estimate the reservoir parameters. The result of the petrophysical analysis showed variations in the reservoir parameters within the two correlated sand bodies with high hydrocabon saturation in sand 1 well 1 while the remaining wells within the correlated wells are water bearing. The porosity values range from 0.19 to 0.32, volume of shale from 0.15 to 0.40, water saturation from 0.20 to 0.92 for the sand bodies.

Modelling the effect of grain anisotropy on inter-granular porosity

Porosity is the dominant factor that determines the exploitable capacity of sedimentary reservoir rocks. Generally, pore heterogeneity is poorly represented in subsurface geological models due to the complexity. Granular mixtures produce complex pore space controlled by grain size, grain shape, and grain sorting. Heterogeneities in pore space volume are present at micro- and nanoscales in granular mixtures due to packing conditions resulting from deposition and diagenesis. In the present study, three-dimensional packing models were generated to provide a realistic description of granular mixtures. Accordingly, this study presents static packing models for unit cells idealised for spherical and elongated grains using cubic, orthorhombic, and rhombohedral packing models. Subsequently, the grain shape effects in terms of elongation degree and grain size distribution in terms of the degree of sorting were evaluated. The mixing effect on the inter-granular porosity for each unit cell packing model was analysed. A range of porosity values was derived using grain parameters generated through in-house developed MATLAB codes from digital FESEM images of sandstone samples. Our study demonstrates that actual grain size does not influence porosity, but for real sandstone samples, the sorting and shape of grains affect porosity values. The range of porosity values estimated by this method can be realistic at the basin level as the grain shape effects replicate sediment maturity. The developed method can be adopted in the distributed spatial models on porosity, especially for basin-scale hydrocarbon resource estimation.