Porosity and Permeability in Reservoirs Research Papers (original) (raw)

Reservoir characterization and structural mapping using integration of well logs and 3-D seismic data was carried out to determine the prolificacy of OVU field, onshore Niger delta. The distribution of reservoir physical parameters (porosity, permeability etc.) and availability of traps that favour hydrocarbon accumulation in the field were evaluated. Four hydrocarbon bearing reservoirs were delineated out of several identified sands in the field out of which three horizons were mapped. Two major growth faults, an antithetic fault and five synthetic faults were delineated. Structural closures were identified as rollover anticlines with the trapping mechanism delineated as a Fault assisted anticlinal structure. The computed range of values for gross thickness, volume of shale, net to gross, water saturation, hydrocarbon saturation, total porosity and absolute permeability with respect to each reservoir are: 18-125m, 9-17%, 83-92%, 18-28%, 62-82%, 21-23%, and 736-3965mD respectively. Hydrocarbon reserves calculations reveals a total reserve of 30.9 billion stock tank barrels of oil. With the very good to excellent calculated values of petrophysical parameters and high hydrocarbon reserve together with the suitable trapping mechanisms makes the study field prolific. Few wells exist in the southwestern corner of the field where a closure is identified in this study. The area should therefore be subjected to further evaluation with a view to increasing the number of wells there.

The objective of this study is to provide information on source organic matter input, depositional conditions and the correlation between crude oils recovered from Sunah oilfield and Upper Jurassic Madbi Formation. A suite of twenty-six crude oils from the Lower Cretaceous reservoirs (Qishn clastic) of the Masila Region (Eastern Yemen) were analysed and geochemically compared with extracts from source rock of the Upper Jurassic (Madbi Formation). The investigated biomarkers indicated that the Sunah oils were derived from mixed marine and terrigenous organic matter and deposited under suboxic conditions. This has been achieved from normal alkane and acyclic isoprenoids distributions, terpane and sterane biomarkers. These oils were also generated from source rock with a wide range of thermal maturity and ranging from early-mature to peak oil window. Based on molecular indicators of organic source input and depositional environment diagnostic biomarkers, one petroleum system operates in the Masila Region; this derived from Upper Jurassic Madbi organic-rich shales as source rock. Therefore, the hydrocarbon exploration processes should be focused on the known location of the Upper Jurassic Madbi strata for predicting the source kitchen.

- by Nabil M . Al-Areeq
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- Sedimentology, Petrophysics, Petroleum, Petrology and Geochemistry

Prepared by ; Nizar Ali hassan Supervised by mr ; allaa aim Objective The objective of this test is to determine the bulk volume, grain volume, pore volume and effective porosityof interconnected pores of a core sample with the use of liquid saturation method Porosity: The term rock refers to the bulk volume of the material, including the grains or crystals as well as the contained void space. The volumetric portion of bulk rock that is not occupied by grains, crystals, or natural cementing material is termed porosity. That is to say, porosity is the ratio of void volume to the bulk volume (grains plus void space). This void space consists of pore space between grains or crystals, in addition to crack space. In sedimentary rocks, the amount of pore space depends on the degree of compaction of the sediment (with compaction generally increasing with depth of burial), on the packing arrangement and shape of grains, on the amount of cementation, and on the degree of sorting. Typical cements are siliceous, calcareous or carbonate, or iron-bearing minerals. Sorting is the tendency of sedimentary rocks to have grains that are similarly sized-, to have a narrow range of sizes ( Poorly sorted sediment displays a wide range of grain sizes and hence has decreased porosity. Well-sorted indicates a grain size distribution that is fairly uniform. Depending on the type of close-packing of the grains, porosity can be substantial. It should be noted that in engineering usage-e.g., geotechnical or civil engineering-the terminology is phrased oppositely and is referred to as grading. A well-graded sediment is a (geologically) poorly sorted one, and a poorly graded sediment is a well-sorted one.

- by Nizar Ali
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- Porosity and Permeability in Reservoirs, Porosity

permeability determination

Reservoir-Porosity-and-Permeability

- by ahmad al imbron
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- Porosity and Permeability in Reservoirs

This study will provide insight to evaluate the potential risks involved with the alteration of in situ effective stresses around the borehole and the risks associated with the reservoir pressure decline. We studied how years of production and reservoir depletion may cause future major geological hazards in the area of study. Wellbore instability and stress distribution analysis around a vertical borehole is also carried out in the Bakken Formation including elastic anisotropy of the layer. We calculated the magnitude of maximum principal horizontal stress as a major input parameter through a new method. This study shows the importance of geomechanical modeling in the petroleum industry with the recent growth of drilling plans in unconventional reservoirs as a novel source of energy where many of them are fine layered, anisotropic and naturally fractured. For this study, dynamic elastic properties were collected through the Bakken Formation using advanced sonic logs. The interpretation of these data is significant in estimating the rock strength, pore pressure, and in situ stresses. The measured dynamic elastic moduli were converted to static ones and were used as input into poroelasticity equations to calculate the magnitude of the horizontal principal stresses. The direction of the maximum principal horizontal stress was determined to be N70E by analyzing fast shear azimuth (FSA) using major fractures which have caused more than 20% shear anisotropy. Finally stress analysis and wellbore stability were performed and compared in the current state of the reservoir stress state and after 5 years of production. Stress polygons are created in the reservoir (horizontal section of the well) to predict future natural hazards. The results confirm the possible occurrence of normal faulting in the region and existence of borehole breakouts after years of production.

- by Ostadhassan, Mehdi and +1
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- Geomechanics, Reservoir Engineering, Reservoir Characterization, Computational geomechanics

The value of water saturation in the reservoir at any point in time determines largely the hydrocarbon in place. This plays a vital role in field development economics. Its determination in well logging from formation resistivity factor approach requires a good knowledge of representative values of the intercept "a" and the cementation factor "m" as used by Archie in his derived relationship between formation resistivity factor "F" and porosity " ".
This paper presents "a" and "m" values and their relationship obtained from formation resistivity factor and porosity data from four different samples with BET surface area range 0.015m2/g to 0.5m2/g of a synthetic model rock (ROBU). Comparison between the resulting model and the widely used ones as reported in the literature was carried out. The formation resistivity factor values of range 4.5 to 8.5 were plotted against the porosity values of range 0.27 to 0.39 on a semi-log plot. Power law regression with R2 fitting of 0.994 was applied to obtain representative values of “a” and “m” and a relationship was derived. Using an assumed range of values of porosity from 0.2 to 0.8, the values of the formation resistivity factor obtained with the derived model were compared with those obtained with the widely used ones presented in the literature.
The result show that the values of the intercept “a” and cementation factor “m” arrived at for the synthetic glass rock, though of the same form are slightly different from Archie’s and Chevron equation. Though the derived model is slightly of different form with the Shell model but their conformity increases with increasing porosity. At high porosity, minimal difference is observed in the values of the formation resistivity factor recorded for both models. At a porosity value of 0.4, the derived model gives the same result as Humble model. However, the model gives higher values of formation resistivity factor at a porosity of less than 0.4 and lower values at a porosity of more than 0.4. The Humble model gives the least value of resistivity factor followed by the derived model. Rather than using existing models, the use of representative values of "a" and "m" in any geological field should be encouraged for proper reservoir management decision.

- by Abasiubong A UDOFIA and +1
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- Reservoir Characterization, Porosity and Permeability in Reservoirs

El alto grado de heterogeneidad de los yacimientos minimiza las posibilidades de comprender la distribución y el comportamiento del flujo de fluidos dentro del espacio poroso debido a la complejidad geológica y variabilidad de sus principales propiedades petrofísicas. Adquirir conocimiento e interpretar estos parámetros por los actuales métodos convencionales resulta insuficiente, lento, complejo y costoso. Para obtener una mejor caracterización de yacimientos altamente heterogéneos permitiendo definir arenas contentivas de hidrocarburos en pozos sin información de núcleos, se desarrolló una metodología que involucra técnicas de Inteligencia Artificial, acompañada de estadística computacional. Se inicia con un modelo de Red Neuronal Probabilística (PNN), para clasificar facies sedimentarias a partir de registros de pozos y descripción sedimentológica de núcleos, seguido de dos modelos de Red Neuronal Backpropagation (BPNN). El primero predice la porosidad efectiva a partir de registros de pozos y muestras de núcleo, el segundo, la permeabilidad de la formación a partir de registros de pozos, del perfil sintético de porosidad neuronal y muestras de núcleo. Asimismo se diseñó un modelo para definir unidades de flujo hidráulicas (UHs) a partir del indicador de zona de flujo (FZI) de núcleos utilizando el clusters k-means. Finalmente se desarrolló un modelo deterministico heurístico para calcular la saturación de agua efectiva en función del FZI a partir de datos de presión capilar. Los modelos de definición de UHs y cálculo de saturación de agua son extrapolados a los pozos utilizando la porosidad y permeabilidad neuronal. Los modelos neuronales implementados mostraron eficacia y óptima generalización en la clasificación de facies y predicción de propiedades petrofísicas al correlacionar los resultados con la data de núcleos. A partir del clusters k-means se definieron las UHs con excelente distinción. El modelo de saturación de agua desarrollado garantiza obtener con más precisión el contenido de hidrocarburos en la formación

- by Wan Hakimi
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- Earth Sciences, Geology, Geophysics, Sedimentology

The thick Eocene carbonate deposits that are newly ascribed as Radwany Formation (previously Thebes Formation) in the October basin within the Gulf of Suez region, are of particular interest for hydrocarbon exploitation. However, no efforts have been directed to investigate their petrophysical characteristics and pore system. This study aims to investigate the petrophysical characteristic, pore system and formation potentiality as a reservoir rock. Thirteen sidewall core samples and sixty thin sections from OCT-X well were studied in order to investigate the lithological characteristics, porosity network. In addition, well logging data and petrophysical and geochemical laboratories measurements including Nuclear Magnetic Resonance (NMR) porosity technique were used to define the petrophysical characteristics. The investigated work revealed that: 1) the pore system is a combination of depositional and diagenetic processes. 2) the dominant porosity types include fracture, interparticle, intra-particle and moldic porosity; NMR indicates mesopores to macropores, 3) petrophysical evaluation and geochemical analysis indicates a self-sourced unconventional reservoir based on its organic richness characteristics unconventional resource opportunity as tight carbonate reservoir, 4) the basal part of the Radwany Formation has a high potential to store hydrocarbon, and it is a potential conventional resource. 6) The linking trends between the petrophysical parameters with sediment microfacies were defined in the studied section, where a significant increasing trend line has been inferred in the direction from wackestone microfacies to packstone microfacies. Finally, the diagenetic process through time has greatly controlled the petrophysical parameters of the Radwany Formation. The gap between Source and Reservoir rocks has been defined based on integrated geochemical and petrophysical characteristics. The studied section has unique multiscale characterization as unconventional and conventional resource.

- by Ahmed E. Radwan
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- Sedimentology, Petrophysics, Reservoir Engineering, Petroleum geology

2017 yılında kayıt olduğum Ankara Üniversitesi, DTCF, Coğrafya bölümünden 2021 yılında birincilik derecesiyle mezun olmuş bulunmaktayım. Bu çalışma lisans bitirme tezi olarak hazırlanmıştır. Bu tezin kapsamını, 2019 yılı Nisan ayında... more

- by Emre Demirel
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- Geography, Physical Geography, Geology, Geomorphology

Recently, natural surfactants had been studied for chemical enhanced oil recovery as opposite to synthetic surfactants due to environmental problems associated with synthetic surfactants. In this study a new plant based natural surfactant, Matricaria chamomilla, is introduced. For this purpose, the interfacial tension values between natural surfactant solution and oil are measured by using the pendant drop method. The results show that Matricaria chamomilla decreased the oil-water interfacial tension values from 30.63 to 12.57 mN/m. Results confirm surface chemical activity of Matricaria chamomilla in comparison with other natural surfactants.

- by soheil shadizadeh and +1
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- Reservoir Engineering, Chemical, Oil and gas, Enhanced Oil Recovery

Permeability network is influenced by ichnofacies in the surface and subsurface sedimentary media, which modifies textural heterogeneity of reservoir rocks by the filling of burrows with the surrounding sediments. In situ measurements of rock permeability from surface analogues of proven subsurface hydrocarbon traps demonstrate the influences of ichnofacies in primary sedimentary structures and resultant high variability within reservoir zones. This work emphasizes on the evaluation of three ichnofacies (i.e., Psilonichnus, Skolithos and Cruziana) that are interdependent and characterized by dense ichnofabrics with sedimentary structures in the exposed rocks of Sandakan Formation. The sedimentary structures associated with ichnofacies are parallel to subparallel, multi-directional trough cross-stratification with current cross laminae and low-angle, undulatory, hummocky cross-stratification (HCS) and oscillation ripple laminated sand with the alteration of silty or sandy mudstones. Results show that the Sandakan Formation was deposited in a transitional environment from a back to foreshore setting and extends to very distal fringes of a proximal lower shoreface or distal delta front to pro-delta. The effective per-meability network in the bioturbated horizons of sandstone and interbedded mudstone is very high (250-950 mD). The integration of ichnofacies and sedimentary structures with high permeability profile suggests that the Sandakan Formation has good reservoir potential with the textural heterogeneity. The implication is that the presence of ichnofacies in sedimentary reservoir horizons can substantially increase secondary porosity and enhance pore connectivity; thus, making them valuable and lucrative subsurface hydrocarbon reservoirs.

Reservoir Characterization involves a holistic approach of describing a reservoir by integrating geologic, geophysical, petrophysical and reservoir engineering using all available data for the characterization of the reservoir’s geometric features (including structural and stratigraphic controls) and Petrophysical properties (including porosity, permeability and fluid saturation). The focus is to understand and identify the flow units of the reservoir and predict the inter-well distributions of relevant reservoir properties. JAY field was characterized via Petrophysical analysis, seismic interpretation and modelling, and rock physics analysis. Porosity and permeability models were generated and combined with petrophysical analysis in characterizing the delineated reservoirs. The rock physics cross-plots were used to quality check the results from the seismic and Petrophysical analysis. The structural interpretation of the 3D seismic data of the field revealed anticlinal structures (four-way closure) which is fault assisted and can thus allow hydrocarbon accumulation. Four of the faults are major listric faults that trend in the Northeast Southwest direction. Amongst the remaining fourteen minor faults, five of them are synthetic faults whose sense of displacement is similar to its associated major faults while others are Antithetic faults. Four horizons were established which indicated the top and base of the two reservoirs. The Petrophysical analysis indicated that the reservoirs have good pore interconnectivity (Average ∅𝑒𝑓𝑓𝑒𝑐𝑡𝑖𝑣𝑒= 24% & 21% and Average 𝐾𝑎𝑣𝑒𝑟𝑎𝑔𝑒 = 9701md & 7737md for Sand A and B respectively.) The rock physics analysis confirmed the result obtained from the Petrophysical analysis and furthermore, it showed that the lithologies within the lower portion of the reservoir were partially cemented. Also, the reservoir is found to be predominated by water followed by gas by both rock physics and petrophysical analysis.

The Kozeny-Carman and Timur-type equations connecting porosity and permeability contain rock-textural constants such as tortuosity and specific surface area. Sometimes these are combined in single factors as Kozeny constant or flow zone index. The partial differential equations of flow in triple-porosity rocks contain transfer factors, interporos-ity flow shape factors between different kinds of pores, as well as their individual storativities. Without knowing these constants, no meaningful permeability prediction or flow simulation is possible. The paper reviews the main ideas of how to find such rock-textural properties directly from the microscopic image.

- by Gabor Korvin
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- Porosity and Permeability in Reservoirs

Porosity and permeability are the key factors in assessing the hydrocarbon productivity of unconventional (shale) reservoirs, which are complex in nature due to their heterogeneous mineralogy and poorly connected nano-and micro-pore systems. Experimental efforts to measure these petrophysical properties posse many limitations, because they often take weeks to complete and are difficult to reproduce. Alternatively, numerical simulations can be conducted in digital rock 3D models reconstructed from image datasets acquired via e.g., nanoscale-resolution focused ion beam-scanning electron microscopy (FIB-SEM) nano-tomography. In this study, impact of reservoir confinement (stress) on porosity and permeability of shales was investigated using two digital rock 3D models, which represented nanoporous organic/mineral microstructure of the Marcellus Shale. Five stress scenarios were simulated for different depths (2,000-6,000 feet) within the production interval of a typical oil/gas reservoir within the Marcellus Shale play. Porosity and permeability of the pre-and post-compression digital rock 3D models were calculated and compared. A minimal effect of stress on porosity and permeability was observed in both 3D models. These results have direct implications in determining the oil-/gas-in-place and assessing the production potential of a shale reservoir under various stress conditions. Conventionally, oil and gas have been recovered from sandstone or carbonate reservoirs where hydrocarbons are trapped in well-connected systems of pores and fractures. Thanks to recent advancements in petroleum technologies , such as horizontal drilling and hydraulic fracturing, oil and gas can also be recovered unconventionally from less-developed mudstone (shale) reservoirs-deep and tight rock formations of heterogeneous lithology and mineralogy with poorly-connected nanometer-/micrometer-size pore systems. Among the key factors in assessing the oil/gas productivity potential of shale reservoirs (also referred as to shales) are the porosity and permeability of these oil-and/or gas-bearing rock formations. Porosity of a rock is the volume of void space, which can be filled with different reservoir fluids (e.g., oil, gas, water) at various saturations, whereas permeability of a rock is the ability of these fluids to flow within and between the pore space. Shales are characterized by very low porosity (typically less than 5%) and very low permeability (typically less than 1,000 nD), which make them challenging in recovering economically viable hydrocarbons. Determining the volume of oil and/or gas present in a reservoir (oil-and/or gas-in-place), and its potential to flow through reservoir pore/fracture system into the wellbore, helps petroleum industry to understand and optimize the producibility of a reservoir. Porosity and permeability of shales are often determined by examining core rock samples recovered from oil/gas wells drilled deep into rock formation. Recently, modern 2D/3D imaging techniques, have been used to investigate mineralogy and porosity in very fine detail, down to the sub-nanometer level 1-4. These methods (and advanced image analysis) have facilitated characterization of the pore morphology within both the organic matter and non-organic (mineral) matrix of shales 5-14. However, there is a little debate whether this imaging data of recovered samples (from thousands of meters) can be considered representative of an unstressed rock. Therefore, the objective of this study was to investigate the effect of reservoir confinement on porosity and permeability of an organic-rich Marcellus Shale rock sample imaged with FIB-SEM nano-tomography at ultra-high-resolution (5 nm/voxel). Porosity and (absolute) permeability under non-confined and confined conditions (at different reservoir depths) were simulated and compared by compressing two digital rock 3D models and re-evaluating the above petrophysical properties.

- by Palash Panja
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- Porosity and Permeability in Reservoirs, Confinement
- by yi Jin
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- Fractal Geometry, Porosity and Permeability in Reservoirs
- by Matteo Cerminara
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- Reservoir Engineering, Geothermal, Fluid flow in porous media, Geothermal Energy
- by Matteo Cerminara
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- Applied Mathematics, Reservoir Engineering, Geothermal, Geothermal Energy

The late-Permian succession of the Upper-Indus Basin is represented by carbonate dominated Zaluch Group, which consists of Amb, Wargal and Chhidru Formations. These formations accumulated on the southwestern shelf of the Paleo-Tethys Ocean, north of hydrocarbon-producing Permian strata of the Arabian Peninsula. The reservoir properties of mixed clasticcarbonate Chhidru Formation are evaluated based on Petrography, Scanning Electron Microscopy (SEM), Energy Dispersive Xrays-Spectroscopy (EDX) and X-ray Diffraction (XRD) techniques. The diagenetic features, ranging from marine (isopachous fibrous calcite, micrite), through meteoric (blocky calcite-I, neomorphism and dissolution) to burial (poikilotopic cement, blocky calcite-II-III, fractures, fracture-filling and stylolites) are recognized. Major porosity types included fracture and moldic, while inter-and intra-particle porosities also existed. The visual porosity from 1.5-7.14% with an average of 5.15% was recognized. The sandstone facies (CMF-4) had the highest average porosity of 10.7%, while siliciclastic grainstone microfacies (CMF-3) showed average porosity of 5.3%. The siliciclastic mudstone microfacies (CMF-1) and siliciclastic wacke-packestone microfacies (CMF-2) showed the lowest porosity of 4.8% and 5.0%, respectively. Diagenetic processes like cementation, neomorphism, stylolitization and compaction have reduced the primary porosities. However, processes of dissolution and fracturing have produced secondary porosity. On average, the Chhidru Formation in Nammal Gorge (Salt Range) showed promising and at Gula Khel Gorge (Trans-Indus) lowest porosity.

Water is recognized as the most important element for economic and social development in developed and less developed countries around the world. Given that there is an inconsistency between the rainfall seasons and high water demand in arid and semi-arid regions, groundwater resources are the primary water source to satisfy various water demands. Surface water reservoirs are constructed to collect and store water during seasons of high rainfall and river flow when there is relatively lower water uses. Due to water-related problems around the world and the potential for severe drought conditions in the future, proper design of new water reservoirs as well as the utilization and conservation of current reservoirs are very crucial. A...

Bioturbation is a typically small scale yet potentially significant geological process altering rock properties by reworking. For many years, bioturbation studies found application in exploration geology to estimate paleobathymetry, interpreting depositional environment and identifying key stratigraphic surfaces. These act as vital inputs to the geological models, for determination of source rock potential, reservoir quality and modeling of petroleum systems. Recently geologists extended the application of bioturbation studies to address production related challenges. Recognizing the bioturbation effects and incorporating them in reservoir simulation models can improve production predictions and enhanced oil recovery operations. This paper discusses bioturbation and its effects on reservoir quality, its performance and production.

- by IMTIAZ CHOUDHURY
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- Materials Engineering, Mechanical Engineering, Materials Science, Metal Cutting

Chlorophyll-a (chla) is a source of water pollution. Monitoring the quality of water in reservoirs is necessary to take any action for protecting the water quality. Traditional methods of sampling are usually costly and time consuming. Also they need skillful labors and some areas are out of reach or sampling at those areas is dangerous. Remote sensing technology could solve problems of high cost, time consuming and unavailability of traditional sampling methods. Landsat 7 imagery is a suitable resource of data because it has been using since a long time ago and could be used to analyze past events. This research aims to investigate the possibility of eutrophication assessment in Ecbatan reservoir using remote sensing images. Field data of the study such as chla were collected in 2010. To reach this aim first the Top of Atmosphere (TOA) reflectance of imagery was calculated for each band. Then the relationship between concentration of chla and reflectance values was determined. Different conversions were applied on reflectance values at the next step to find the best regression equation for estimating the concentration of chla. The best model for estimating the concentration of chla was based on the band ratios. The values of R 2 Adj and SE are 0.91 and 0.04 respectively for this model. Based on the results of this research Landsat 7 is capable of reflecting the eutrophication problem in a small reservoir as Ecbatan.

- by Kaveh Ostad-Ali-Askari and +1
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- Reservoir Engineering, Microporosity of Carbonate reservoirs, Reservoir Characterization, Reservoir Simulation

Sonic velocities of Pleistocene travertines were measured under variable confining pressures. Combined with petrographical characteristics and petrophysical data, i.e. porosity, permeability and density, it was determined that travertine porosity, pore types and cementation control compressional-wave (Vp) and shear-wave velocity (Vs). At 40 MPa confining pressures, Vp ranges between 3695 and 6097 m/s and Vs between 2037 and 3140 m/s. Velocity variations in travertines are, as with all carbonates, primarily linked to sample heterogeneity, i.e. differences in fabric, texture and porosity. They thus not necessarily emanate from changes in mineralogy or composition. Body wave velocities have a positive correlation with sample density and an inverse correlation with porosity. The travertines, sampled in extensional settings with normal faulting activity, define a specific compressional-wave velocity (y-axis) versus porosity (x-axis) equation, i.e. (log(y) ¼ 0.0048x þ 3.7844) that differs from the Vp-porosity paths defined by marine carbonates. Acoustic wave velocities are higher for travertines than for marine carbonates. Travertine precipitates form rigid rock frames, often called framestone, with large primary pores. Marine carbonates on the other hand often consist of (cemented) transported sediments, resulting in a rock frame that permits slower wave propagation when compared to the continental limestones. Acoustic velocity variations are linked to variations in pore types. Mouldic pores (macropores) show faster wave propagation than expected from their total porosities. Microporosity, interlaminar and interpeloidal porosity result in slower acoustic velocities. Framework pores and micro-moulds are associated with lowered acoustic velocities, while vug porosity is found above, on and below the general velocity-porosity trend. Not only the pore type, but also pore shapes exert control on body wave velocities. Cuboid-and rod-like pore shapes increase the velocity, while plate-and blade-like pore shapes have a negative effect on the velocity. The study demonstrates how seismic sections in travertine systems can contain seismic reflections that are not caused by non-carbonate intercalations, but relate to geobody boundaries, in which the seismic expression is function of porosity, pore types and shapes. This study provides and relates petrophysical data, i.e. porosity, permeability and acoustic velocities of travertines and is of importance for the interpretation of seismic reflection data in subsurface continental carbonate reservoirs.

- by Hannes Claes and +1
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- Travertines, Porosity and Permeability in Reservoirs, Porosity, Travertine and Tufa formation

- by Andreas Wiegmann
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- Porosity and Permeability in Reservoirs, Confinement

In this study the optimum preparation conditions of bio-char were achieved as a by-product of the bio-oil production process from oil palm shell as an agricultural waste material. To investigate the possibility of utilizing bio-char as an adsorbent for wastewater treatment and other applications, a central composite design was applied to investigate the influence of carbonization temperatures, nitrogen flow rates, particle sizes of precursor, and duration on the bio-char yield and methylene blue adsorption capacity as the responses. Methylene blue was chosen in this study due to its wide application and known strong adsorption onto solids. Two quadratic models were developed for the responses and to calculate the optimum operating variables providing a compromise between yield and adsorption. From the analysis of variance, temperature was identified as the most influential factor on each experimental design response. The predicted yield and adsorption capacity was found to agree sat...

In this work, untreated bovine cortical bones (BCBs) were exposed to a range of heat treatments in order to determine at which temperature the apatite develops an optimum morphology comprising porous nano hydroxyapatite (nanoHAp)... more