Showing papers on "Effective porosity published in 2015"
TL;DR: There are a large number of methods for quantifying porosity, and an increasingly complex idea of what it means to do so as discussed by the authors, which is why it is important to quantify the relationships between porosity and storage, transport and rock properties, however, the pore structure must be measured and quantitatively described.
Abstract: Porosity plays a clearly important role in geology. It controls fluid storage in aquifers, oil and gas fields and geothermal systems, and the extent and connectivity of the pore structure control fluid flow and transport through geological formations, as well as the relationship between the properties of individual minerals and the bulk properties of the rock. In order to quantify the relationships between porosity, storage, transport and rock properties, however, the pore structure must be measured and quantitatively described. The overall importance of porosity, at least with respect to the use of rocks as building stone was recognized by TS Hunt in his “Chemical and Geological Essays” (1875, reviewed by JD Dana 1875) who noted:
> “Other things being equal, it may properly be said that the value of a stone for building purposes is inversely as its porosity or absorbing power.”
In a Geological Survey report prepared for the U.S. Atomic Energy Commission, Manger (1963) summarized porosity and bulk density measurements for sedimentary rocks. He tabulated more than 900 items of porosity and bulk density data for sedimentary rocks with up to 2,109 porosity determinations per item. Amongst these he summarized several early studies, including those of Schwarz (1870–1871), Cook (1878), Wheeler (1896), Buckley (1898), Gary (1898), Moore (1904), Fuller (1906), Sorby (1908), Hirschwald (1912), Grubenmann et al. (1915), and Kessler (1919), many of which were concerned with rocks and clays of commercial utility. There have, of course, been many more such determinations since that time.
There are a large number of methods for quantifying porosity, and an increasingly complex idea of what it means to do so. Manger (1963) listed the techniques by which the porosity determinations he summarized were made. He separated these into seven methods for …
788 citations
TL;DR: In this article, the authors measured the effective and absolute permeability of hydrate-bearing sandy sediment using natural sediment cores obtained from a methane hydrate reservoir in the Eastern Nankai Trough off the shore of Japan.
165 citations
TL;DR: In this paper, the authors focus on how reactive fluids can move through "tight rocks" which have a very low intrinsic permeability and how secondary porosity is generated by fluid-mineral reactions.
Abstract: The term porosity is very widely used in geosciences and normally refers to the spaces between the mineral grains or organic material in a rock, measured as a fraction of the total volume. These spaces may be filled with gas or fluids, and so the most common context for a discussion of porosity is in hydrogeology and petroleum geology of sedimentary rocks. While porosity is a measure of the ability of a rock to include a fluid phase, permeability is a measure of the ability for fluids to flow through the rock, and so depends on the extent to which the pore spaces are interconnected, the distribution of pores and pore neck size, as well as on the pressure driving the flow.
This chapter will be primarily concerned with how reactive fluids can move through ‘tight rocks’ which have a very low intrinsic permeability and how secondary porosity is generated by fluid–mineral reactions. A few words about the meaning of the title will help to explain the scope of the chapter:
1. “Fluid–mineral interaction”: When a mineral is out of equilibrium with a fluid, it will tend to dissolve until the fluid is saturated with respect to the solid mineral. We will consider fluids to be aqueous solutions, although many of the principles described here also apply to melts. The generation of porosity by simply dissolving some minerals in a rock is one obvious way to enhance fluid flow. Dissolution of carbonates by low pH solutions to produce vugs and even caves would be one example. However, when considering the role of fluid–mineral reaction during metamorphism the fluid provides mechanisms that enable re-equilibration of the rock, i.e., by replacing one assemblage of minerals by a more stable assemblage. This not only involves the dissolution of the parent mineral phases, but the …
108 citations
TL;DR: In this paper, a series of effective porosity and permeability determinations have been conducted under different overburden stresses using an automated permeameter-porosimeter considering the directional distribution of natural fractures in coal.
Abstract: Although the relationships among stress, effective porosity and permeability of coal are a fundamental research topic that has been studied for decades and are widely used in analyzing the mechanical behavior of coal seams and predicting coalbed methane production, most relevant studies are based on idealized models and do not consider the influence of natural fracture distributions. To obtain a comprehensive understanding of the interrelationships among stress, effective porosity and permeability of coal, a series of effective porosity and permeability determinations have been conducted under different overburden stresses using an automated permeameter–porosimeter considering the directional distribution of natural fractures in coal. The experimental results show that the directional distribution of natural fractures provides a substantial contribution to the anisotropy of the effective porosity and absolute permeability of coal, which exponentially decrease with increasing overburden stress. An existing permeability model was modified to reflect the influence of the natural fracture distribution on the power law relationship between effective porosity and permeability, i.e., the exponent is not constant, but a variable related to the natural fracture distribution. The anisotropic effective porosity sensitivity and stress sensitivity of coal are also discussed, and the coal mass is shown to have the highest effective porosity sensitivity and lowest stress sensitivity in the direction perpendicular to the bedding planes compared to those in other directions.
47 citations
TL;DR: In this paper, a combination of small and ultrasmall-angle neutron scattering (U)SANS with scanning electron microscope (SEM)/backscattered electron imaging was used to analyze the pore structure of clay- and carbonate-rich samples of the Eagle Ford Shale.
Abstract: Porosity and permeability are key variables that link the thermal-hydrologic, geomechanical, and geochemical behaviorin rocksystemsand arethusimportantinputparametersfor transportmodels. Neutronscattering studies indicate that the scales of pore sizes in rocks extend over many orders of magnitude from nanometer-sized pores with huge amounts of total surface area to large open fracture systems (multiscale porosity). However, despite considerable efforts combining conventional petrophysics, neutron scattering, and electron microscopy, the quantitativenature of this porosityintightgas shales, especiallyatsmallerscalesand overlargerrockvolumes, remains largely unknown. Nor is it well understood how pore networks are affected by regional variation in rock composition and properties, thermal changes across the oil window (maturity), and, most critically, hydraulic fracturing. To improve this understanding, we have used a combination of small- and ultrasmall-angle neutron scattering (U)SANS with scanning electron microscope (SEM)/backscattered electron imaging to analyze the pore structure of clay- and carbonate-rich samples of the Eagle Ford Shale. This formation is hydrocarbon rich, straddles the oil window, and is one of the most actively drilled oil and gas targets in the United States. Several important trends in the Eagle Ford rock pore structure have been identified using our approach. The (U)SANS results reflected the connected (effective) and unconnected porosity, as well as the volume occupied by organic material. The latter could be separated using total organic carbon data and, at all maturities, constituted a significant fraction of the apparent porosity. At lower maturities, the pore structure was strongly anisotropic. However, this decreased with increasing maturity, eventually disappearing entirely for carbonate-rich samples. In clay- and carbonate-rich samples, a significant reduction in total porosity occurred at (U)SANS scales, much of it during initial increases in maturity. This apparently contradicted SEM observations that showed increases in intraorganic porosity with increasingmaturity. Organic-rich shales are, however, a very complex material fromthe point of view of scattering studies, and a more detailed analysis is needed to better understand these observations.
35 citations
TL;DR: In this paper, the authors show that dual-porosity flow is common, with advective flow through fracture networks and immobile storage in the matrix, and in some cases a dual-or multiple-permeability approach provides better simulations of aquifer behavior.
32 citations
TL;DR: A C++ GPU code based on three-dimensional lattice Boltzmann method has been developed and used for investigating the effects of the porosity, size of particles, pore shape, tortuosity, and particle size distribution on the permeability coefficient of granular materials.
Abstract: Permeability of porous materials is an important characteristic which is extensively used in various engineering disciplines. There are a number of issues that influence the permeability coefficient among which the porosity, size of particles, pore shape, tortuosity, and particle size distribution are of great importance. In this paper a C++ GPU code based on three-dimensional lattice Boltzmann method (LBM) has been developed and used for investigating the effects of the above mentioned factors on the permeability coefficient of granular materials. Multirelaxation time collision scheme of the LBM equations is used in the simulator, which is capable of modeling the exact position of the fluid-solid interface leading to viscosity-independent permeabilities and better computational stability due to separation of the relaxations of various kinetic models. GPU-CPU parallel processing has been employed to reduce the computational time associated with three-dimensional simulations. Soil samples have been prepared using the discrete element method. The obtained results have demonstrated the importance of employing the concept of effective porosity instead of total porosity in permeability relationships. The results also show that a threshold porosity exists below which the connectivity of the pores vanishes and the permeability of the soils reduces drastically.
32 citations
TL;DR: In this paper, a number of large-scale vuggy carbonate oil and gas fields have been discovered in Chinese marine carbonate fields, which are characterized by high porosity, low-porosity, and a uniform temperature and pressure system.
31 citations
TL;DR: In this article, the authors describe the Middle Jurassic Upper Safa reservoirs in the Western Desert, Egypt using data from wireline logs (gamma ray, density, neutron, sonic, and resistivity) from 14 wells.
Abstract: Identification of the types of the depositional environments that have control or influence on the distribution of petrophysical parameters is required to assess the potential utility of these parameters in the reservoir analysis. The primary depositional facies plays an important role in the reservoir quality and assessment of the petrophysical characteristics of hydrocarbon bearing zones in exploration and development operations. Petrophysical characteristics, depositional environment, and hydrocarbon prospectivity of the Middle Jurassic Upper Safa reservoirs in the Obaiyed Field (Western Desert, Egypt) are described using data from wireline logs (gamma ray, density, neutron, sonic, and resistivity) from 14 wells. Petrophysical characteristics of Upper Safa reservoirs (unit A and unit B) change significantly with variations of depositional facies and lithology. These units are interpreted to be composed of fluvial channel sands (unit A) and tidal channel sands (unit B) based on a gamma ray curve signatures. Litho-saturation analysis, petrophysical parameters, and net pay thickness maps of the Upper Safa reservoirs show variations along the study area. The main factor controlling differences in petrophysical properties and thickness for these reservoirs is the type of sandstone facies. Shales cause a major reduction in the porosity and gas saturation of the reservoir sandstones especially in the unit B reservoir which has dispersed and laminated shale and low resistivity net pay zone. The best reservoir characteristics belong to the unit A, which has high effective porosity (PHIE), low shale content (V
sh), and high gas saturation (S
g). Maps of reservoir parameters based on precise understanding of its depositional environment indicate the location of possible sites for future gas development activities in the Obaiyed Field.
26 citations
TL;DR: In this article, a new three-dimensional reservoir space description and reserve calculation method for layered, fracture-cavity carbonate reservoirs is used to calculate the reserves of X block in the Halahatang oilfield in the Tarim Basin.
21 citations
TL;DR: In this article, the authors investigate the porosity of a porous medium as given in Darcy's law and show that porosity can be related to porosity, in the sense of Kozeny-Carman, through fundamental and well-defined pore structure parameters: characteristic length, constriction, and tortuosity.
Abstract: In this article we investigate the permeability of a porous medium as given in Darcy's law. The permeability is described by an effective hydraulic pore radius in the porous medium, the fluctuation in local hydraulic pore radii, the length of streamlines, and the fractional volume conducting flow. The effective hydraulic pore radius is related to a characteristic hydraulic length, the fluctuation in local hydraulic radii is related to a constriction factor, the length of streamlines is characterized by a tortuosity, and the fractional volume conducting flow from inlet to outlet is described by an effective porosity. The characteristic length, the constriction factor, the tortuosity and the effective porosity are thus intrinsic descriptors of the pore structure relative to direction. We show that the combined effect of our pore structure description fully describes the permeability of a porous medium. The theory is applied to idealized porous media, where it reproduces Darcy's law for fluid flow derived from the Hagen-Poiseuille equation. We also apply this theory to full network models of Fontainebleau sandstone, where we show how the pore structure and permeability correlate with porosity for such natural porous media. This work establishes how the permeability can be related to porosity, in the sense of Kozeny-Carman, through fundamental and well-defined pore structure parameters: characteristic length, constriction, and tortuosity.
TL;DR: The area method was more effective in characterizing flat sheet meshes while the weight method was perhaps more accurate in describing stereoscopic void space for 3D structure devices.
Abstract: Inguinal hernia repairs are among the most frequent operations performed worldwide. This study aims to provide further understanding of structural characteristics of hernia prostheses, and better comprehensive evaluation. Weight, porosity, pore size and other physical characteristics were evaluated; warp knitting structures were thoroughly discussed. Two methods referring to ISO 7198:1998, i.e., weight method and area method, were employed to calculate porosity. Porosity ranged from 37.3% to 69.7% measured by the area method, and 81.1% to 89.6% by the weight method. Devices with two-guide bar structures displayed both higher porosity (57.7%-69.7%) and effective porosity (30.8%-60.1%) than single-guide bar structure (37.3%-62.4% and 0%-5.9%, respectively). Filament diameter, stitch density and loop structure combined determined the thickness, weight and characteristics of pores. They must be well designed to avoid zero effective porosity regarding a single-bar structure. The area method was more effective in characterizing flat sheet meshes while the weight method was perhaps more accurate in describing stereoscopic void space for 3D structure devices. This article will give instructive clues for engineers to improve mesh structures, and better understanding of warp knitting meshes for surgeons.
TL;DR: In this article, a combination of different techniques can be used to better understand rock properties of complex reservoirs, thereby helping to reduce reservoir uncertainty, and mean data from laser grain-size analysis are comparable to point-counted grain size, and both are considered as viable analytical methods.
Abstract: Clay- and lithic-rich sandstones are difficult to characterize through uncored well sections in terms of their grain size, porosity, and mineralogy, all of which are required for assessing reservoir quality and production performance. This paper presents results from a study through one such interval and shows how a combination of different techniques can be used to better understand rock properties of complex reservoirs, thereby helping to reduce reservoir uncertainty. In this study, mean data from laser grain-size analysis are comparable to point-counted grain size, and both are considered as viable analytical methods. Automated quantitative evaluation of minerals by scanning electron microscopy (QEMSCAN®) provides a further useful and consistent grain-size measurement that can be applied to both core and cuttings samples. The QEMSCAN has also proved to be a valuable technique in the mineralogical analysis of sandstones that are lithic, clay- and feldspar-rich, eliminating the subjective nature that is inherent with optical analysis. Results from the studied interval show that porosity measured by conventional core analysis (CA) and mercury injection capillary pressure (MICP) analysis are generally comparable with log-derived total porosity. Porosity measured from point-counting and QEMSCAN techniques is significantly lower than total porosity, with the QEMSCAN porosity locally equivalent to log-derived effective porosity. Both point-count and QEMSCAN porosities show better correlations with permeability ( and 0.94, respectively) than total porosity values ( and 0.60 CA and MICP, respectively), suggesting that they might provide a measure of effective porosity in high-quality reservoir rocks.
TL;DR: In this paper, a new scaling equation based on fractal geometry was proposed to scale porosity in carbonate rocks, and the effect of magnification in scanning-electronic-microscope and thin-section images was evaluated.
Abstract: The study of scaling porosity in carbonate rocks has great importance because (1) porosity measurements are usually made at scales that are different from the one of interest and (2) carbonate formations contain most of the hydrocarbon reservoirs and aquifers in the world. Despite these facts, scaling porosity in heterogeneous media, such as carbonate rocks, is still an open problem. The heterogeneity of carbonate rocks mainly resides in their complex texture. We have extended previous studies on carbonate multifractal behavior in pore space morphology at different scales, and we have developed a new equation based in fractal geometry that could be used to scale the porosity. In our methodology, we (1) perform a multifractal analysis in thin-section images of a set of complex carbonate rocks from the Lower Cretaceous, (2) review the effect of magnification in scanning-electronic-microscope and thin section images, (3) deduce a new scaling equation for porosity, and finally (4) evaluate this equati...
TL;DR: In this paper, a dual-porosity medium porosity interpretation model was built on the basis of drilling data of Fuling Gasfield and Changning gas block in the Sichuan Basin.
TL;DR: In this paper, the authors evaluated two pore volume compressibility models that are currently discussed in the literature (Horne, 1990; Jalalh, 2006b) for carbonate rock samples from the three following sedimentary basins in North America that are known for their association with hydrocarbon deposits.
TL;DR: In this paper, the axial dispersion coefficient as well as the effective porosity were calculated from the residence time distribution curves, and a linear relationship between the dispersion coefficients and the interstitial fluid velocity was found.
TL;DR: In this paper, a self-developed experimental system called Intelligent Testing System for Water Absorption in Deep Soft Rocks (ITSWADSR) was utilized to analyze the hydrophilic behaviors of natural soft rock at high stress state.
Abstract: In order to study features of rock–water interaction, a self-developed experimental system called Intelligent Testing System for Water Absorption in Deep Soft Rocks (ITSWADSR) was utilized to analyze the hydrophilic behaviors of natural soft rock at high stress state. Combining X-ray diffraction and mercury injection test, main influencing factors on hydrophilic characteristics were studied. According to the results, it could be concluded as the following: (1) the effective porosity, and the content of illite, illite/smectite formation (S = 5%) and kaolinite have positive correlation with the water absorption capacity of rock; meanwhile, the initial moisture content, fractal dimension of effective pores, illite/smectite formation (S = 30%) and chlorite present negative correlation; (2) among the positive factors, the ascending order is kaolinite, illite/smectite formation (S = 5%) and illite; (3) the descending order among the negative factors are chlorite, illite/smectite formation (S = 30%) and fractal dimension of the effective pores; (4) influence of effective porosity on the pressurized water absorbing capacity of rock is minimal, while it is maximal in the process of no pressurized water absorption.
TL;DR: In this paper, the authors examined the possibility of determining the pore space in microporous rocks using a set of methods: differential thermal analysis, retort distillation, and Dean-Stark.
TL;DR: In this article, a series of water absorption tests on dried soft rock have been conducted by the intelligent testing system for water absorption in deep soft rock, including tests of water absorbing with and without pressure.
Abstract: A series of water absorption tests on dried soft rock have been conducted by the intelligent testing system for water absorption tests in deep soft rock, including tests of water absorption with and without pressure. The results show that the water absorbing capacity of rock with a certain pressure is larger than that of rock without pressure; however, the relationship between the water absorbing percentage and the time can be expressed by w ( t ) = a (1 − e - bt ). In bi-logarithmic coordinates, the hydrophilic relationship with time in tests with pressure could be characterized by linearity, while they present concave or convex in tests without pressure. Based on the hypothesis that each influential factor is irrelevant and they have a linear correlation with the water absorbing capacity, we calculated the weight coefficient of each factor according to experimental results under different conditions. The calculations demonstrate that the effective porosity, content of smectite and kaolinite are all positively correlated with the water absorption capacity of rock; meanwhile, the fractal dimension of the effective pores presents a negative correlation with the water absorption capacity of rock. The water absorption capacity with pressure increases with increasing illite, chlorite and chlorite/smectite formation and a decrease in illite/smectite formation and the fractal dimension of the effective pores, while it is opposite in tests without pressure. The weight coefficient of smectite is smallest among positive factors, and the fractal dimension of the effective pores is the smallest amongst the negative factors.
01 Jan 2015
TL;DR: In this paper, a new classification of the reservoir quality of rocks for CGS in terms of gas permeability and porosity was proposed for the sandstones of the Deimena Formation covered by Lower Ordovician clayey and carbonate cap rocks in the Baltic sedimentary basin.
Abstract: The objectives of this study were (1) to review current recommendations on storage reservoirs and classify their quality using experimental data of sandstones of the Deimena Formation of Cambrian Series 3, (2) to determine how the possible CO2 geological storage (CGS) in the Deimena Formation sandstones affects their properties and reservoir quality and (3) to apply the proposed classification to the storage reservoirs and their changes during CGS in the Baltic Basin.
The new classification of the reservoir quality of rocks for CGS in terms of gas permeability and porosity was proposed for the sandstones of the Deimena Formation covered by Lower Ordovician clayey and carbonate cap rocks in the Baltic sedimentary basin. Based on permeability the sandstones were divided into four groups showing their practical usability for CGS (‘very appropriate’, ‘appropriate’, ‘cautionary’ and ‘not appropriate’). According to porosity, eight reservoir quality classes were distinguished within these groups.
The petrophysical, geochemical and mineralogical parameters of the sandstones from the onshore South Kandava and offshore E6 structures in Latvia and the E7 structure in Lithuania were studied before and after the CO2 injection-like alteration experiment. The greatest changes in the composition and properties were determined in the carbonate-cemented sandstones from the uppermost part of the South Kandava onshore structure. Partial dissolution of pore-filling carbonate cement (ankerite and calcite) and displacement of clay cement blocking pores caused significant increase in the effective porosity of the samples, drastic increase in their permeability and decrease in grain and bulk density, P- and S-wave velocity, and weight of the dry samples. As a result of these alterations, carbonate-cemented sandstones of initially ‘very low’ reservoir quality (class VIII), ‘not appropriate’ for CGS, acquired an ‘appropriate’ for CGS ‘moderate’ quality (class IV) or ‘very appropriate’ ‘high-2’ reservoir quality (class II). The permeability of the clay-cemented sandstones of ‘very low’ reservoir quality class VIII from the lower part of the E7 reservoir was not improved. Only minor changes during the alteration experiment in the offshore pure quartz sandstones from the E6 and E7 structures caused slight variations in their properties. The initial reservoir quality of these sandstones (‘high-1’ and ‘good’, classes I and III, respectively, in the E6 structure, and ‘cautionary-2’, class VI in the E7 structure) was mainly preserved.
The reservoir sandstones of the Deimena Formation in the South Kandava structure had an average porosity of 21%, identical to the porosity of rocks in the E6 structure, but twice higher average permeability, 300 and 150 mD, respectively. The estimated good reservoir quality of these sandstones was assessed as ‘appropriate’ for CGS. The reservoir quality of the sandstones from the E7 offshore structure, estimated as ‘cautionary-2’ (average porosity 12% and permeability 40 mD), was lowest among the studied structures and was assessed as ‘cautionary’ for CGS.
Petrophysical alteration of sandstones induced by laboratory-simulated CGS was studied for the first time in the Baltic Basin. The obtained results are important for understanding the physical processes that may occur during CO2 storage in the Baltic onshore and offshore structures.
TL;DR: In this paper, path-percolation theory was applied to randomly generate porous media, and effective porosities of these domains were determined using a statistical approach with confidence levels of 95, 97, and 99%.
20 Jul 2015
TL;DR: In this article, a study of the unconventional oil potential of the marine late Jurassic Kimmeridge Clay Formation of the southern Viking Graben area of the UK and Norwegian sectors of the North Sea is presented.
Abstract: Rock-Eval pyrolysis analysis of unconventional mudstone reservoirs use the S1 peak (kg free liquid per tonne of rock) to determine the volume of oil that can be potentially produced by hydraulic fracking. The data presented in this paper were obtained from a study of the unconventional oil potential of the marine late Jurassic Kimmeridge Clay Formation of the southern Viking Graben area of the UK and Norwegian sectors of the North Sea. Typical marine silty mudstones with >2%TOC contains <1kg/t (0.1wt. %) of free oil when immature at depths <2.5km and Tmax <420°C. The peak saturation of free oil rises to values of 12kg/t, with a typical peak average of ~6kg free oil/tonne of rock (0.6wt.%). Such average values are reached when mature at depths of 3.4km and Tmax values of 435°C in the North Sea. Converting Rock-Eval S1 yields to volume percent, the average mature mudstone contains about 1.8vol% of free oil. How does this compare with the accessible porosity of the mudstone? Conventional log analysis for porosity measures everything that is not mineral grains as pore space, but fluid injection methods (mercury, helium) measure the effective porosity, a more realistic measure of open pores that are available to petroleum. In the case of log-derived porosities, closed porosity and structured (fixed) water are counted, but appear not to be open to Rock-Eval free oil (S1) and hence for ‘saturation’. Comparing typical peak S1 volumes (1.8 vol. %) against mudstones porosities (1.62 vol. %), suggests, within error, that the open porosity is fully saturated with oil at peak maturity. In addition the distributions of porosity and S1 yields are similar. However, if the S1 yield at peak maturity is totally a function of porosity; the S1 yield should be independent of the amount or type of kerogen. This is not so. Plotting S1 yield against TOC shows a strong positive correlation, with a gradient of 0.7kg/t per 1%TOC and an intercept of about 1%TOC. This gradient indicates that the S1 ‘oil’ is partitioned between the kerogen and the porosity. Given the size of the molecules relative to the micro-porosity of the largely amorphous kerogen, the oil is likely to be absorbed onto the kerogen surface. This explains the asymmetry (or shoulders) seen on the pyrograms of S1 peaks, the main peak representing easily liberated liquids in open porosity and the shoulder the more strongly adsorbed liquids. The additional adsorbed liquid is more efficiently recovered and can be quantified by solvent extraction of the mudstones, where saturates + aromatics are shown to be over twice the Rock-Eval S1 yield. Thus, like Unconventional gas, this evidence suggests that Unconventional liquids too may derive from ‘free’ and ‘adsorbed’ oil, and that both are mainly stored within organic (kerogen) porosity.
23 Feb 2015
TL;DR: Lee et al. as discussed by the authors extended the Texas AaM Flow and Transport Simulator (FTSim) with a fully functional capability that describes kerogen pyrolysis and accompanying system changes.
Abstract: Author(s): Lee, K; Moridis, GJ; Ehlig-Economides, CA | Abstract: Oil shale, which is composed of abundant organic matter called kerogen, is a vast energy source. Pyrolysis of kerogen in oil shales releases recoverable hydrocarbons. Here, we describe the pyrolysis of kerogen with an in-situ upgrading process, which is applicable to the majority of oil shales. The pyrolysis is represented by six kinetic reactions resulting in 10 components and four phases. Expanding the Texas AaM Flow and Transport Simulator (FTSim), which is a variant of the TOUGH +simulator (Moridis 2014), we develop a fully functional capability that describes kerogen pyrolysis and accompanying system changes. The simulator describes the coupled process of mass transport and heat flow through porous and fractured media and includes physical and chemical phenomena of reservoir systems. The simulator involves a total of 15 thermophysical states and all transitions between them and computes a simultaneous solution of 11 mass- and energy-balance equations per element. The simulator solves the equations in a fully implicit manner by solving Jacobian matrix equations with the Newton-Raphson iteration method. To conduct a realistic simulation, we account for geological structure of oil-shale reservoirs and physical properties of bulk-oil shale rocks by considering phases and components in the pores. In addition, we involve interaction between fluids and porous media, diverse equations of state (EOSs) for computation of fluid properties, and numerical modeling of fractured media. We intensively reproduce the field-production data of Shell Insitu Conversion Process (ICP) implemented in the Green River formation by conducting sensitivity analyses for the diverse reservoir parameters, such as initial effective porosity of the matrix, oil-shale grade, and the spacing of the natural-fracture network. We analyze the effect of each reservoir parameter on the hydrocarbon productivity and product selectivity. The simulator provides a powerful tool to quantitatively evaluate production behavior and dynamic-system changes during in-situ upgrading of oil shales and subsequent fluid production by thoroughly describing a reservoir model, phases and components, phase behavior, phase properties, and evolution of porosity and permeability.
Journal Article•
TL;DR: Anomalously high porosity zones are desserts for oil and gas exploration in deep layers in sedimentary basins as discussed by the authors, and the research results are important for the deep layers.
Abstract: Anomalously high porosity zone refers to a zone where reservoirs with anomalously high porosity concentrate,and the porosities are higher than the maximum porosity of reservoirs experienced normal compaction.Anomalously high porosity zones are desserts for oil and gas exploration in deep layers in sedimentary basins.Significant studies have been conducted by worldwide scholars,and the research results are important for the oil and gas exploration in deep layers.From aspects of concepts,classification scheme,types,reservoir pores,origin and prediction of anomalously high porosity zones,this paper summarized the current research progress.Studies show that the distribution of the anomalously high porosity zones can be determined by the porosity compaction curve or some other equivalent curves.The anomalously high porosity zones can be subdivided into primary pore anomalously high porosity zone and secondary pore anomalously high porosity zone.Primary pores dominant in the former type and geological processes beneficial to porosity preservation are the controlling factors.Secondary pores dominate in the other type and geological processes beneficial to dissolution are the controlling factors.Then the features and genetic mechanisms of anomalously high porosity zones in the petroliferous basins of China were summarized.These zones have the features of wide development and various types.The zones developed in layers of a big depth range and wide geological age,and the zones developed in different sedimentary facies in various basins,and both the primary and secondary types developed.And finally,the existing problems and research trend on anomalously high porosity zone were proposed.
TL;DR: In this paper, a mathematical model of multi-stage fractured horizontal wells in shale gas reservoirs is built, which considers the influence of viscous flow, Knudsen diffusion, surface diffusion, and adsorption layer thickness.
TL;DR: In this article, the authors delineated and mapped the hydrocarbon-bearing reservoir HD2000 from surface seismic sections and well logs within the depth interval of 5,700 ft and 6,200 ft.
Abstract: This study delineates and maps the hydrocarbon-bearing reservoir HD2000 from surface seismic sections and well logs within the depth interval of 5,700 ft (1,737 m) and 6,200 ft (1,890 m) The objective is to establish the geometry, reservoir distribution, delineate hydrocarbon-bearing reservoirs from surface seismic sections and well logs In this process, a 3-D structural interpretation and estimation of the volume of hydrocarbon in place of the reservoirs was carried out Well-to-seismic tie revealed that hydrocarbon-bearing reservoirs were associated with direct hydrocarbon indicators (bright spots and dim spots) on the seismic sections Two horizons were studied (HD2 and HD2_version2) and several faults mapped for the purpose of carrying out 3-D subsurface structural interpretation This was used in generating the time structure maps From the maps, it was observed that the principal structure responsible for hydrocarbon entrapment in the field was the anticlinal structure at the center of the field which tied to the crest of the rollover structure seen on the seismic sections Check shots from the control well were used to create a velocity model from which the time to depth conversion was made Horizon slice taken shows the reservoir spans a thickness of 400 ft Direct hydrocarbon indicators were used to map the reservoir boundary They were seen on the reflection amplitude maps as high amplitude zones (bright spots) and low amplitude zones (dim spots) Reservoir area extent estimated by square grid template method revealed that reservoir HD2000 had an area estimate of 529 km2 The results show the effectiveness of the estimation techniques in the lateral prediction of reservoir properties, discriminating litho-fluid and determining the porosity, saturation, net-to-gross ratio, and moreover the reserve volume Hydrocarbon saturation varied between 064 and 065, while effective porosity varied between 031 and 032 Estimation of the volume of hydrocarbon in place revealed that the delineated reservoir HD2000 contained an estimate of 776,545,41822 barrels (123,460,8554 cm3) of hydrocarbon which shows great potential of considerable size
TL;DR: In this article, a gas bearing carbonate reservoir in Persian Gulf was evaluated using traditional logging tools such as Gamma Ray (GR), Resistivity Logs, Density, Neutron and Sonic.
Journal Article•
TL;DR: In this paper, a comparative analysis of the Simandoux model and the Archie model was carried out with the aim of determining the hydrocarbon potential of the shaly-sand reservoirs using the composite logs comprising gamma ray, resistivity and porosity logs.
Abstract: The comparative analyses of four wells in “X” Field within the Niger Delta were carried out with the aim of determining the hydrocarbon potential of the shaly-sand reservoirs using the Archie and Simandoux Models. The plots of effective porosity against volume of shale were used to determine the clay distribution. Composite logs comprising gamma ray, resistivity and porosity logs (density and neutron) were utilized to generate petrophysical properties in four (4) wells using Simandoux and Archie Models. Also, statistical analysis of water saturation values for both models were analysed and compared. The results of the plots of effective porosity against shale volume reveal decrease in effective porosity against increase in shale volume. The trends of the plots indicate laminated shale distribution mainly while only one hydrocarbon zone in well 3 denotes dispersed shale. Both models show very good to excellent porosity values (21-36%), and favourable hydrocarbon movability index (0.09-0.43). The statistical analyses show lower standard deviation and mean values of water saturation for Simandoux (0.008-0.2) and (0.03-0.2) when compared with that of Archie Model (0.08-0.24) and (0.15-0.5) which is indicative of higher hydrocarbon saturation than the Archie Model. At 5% error level, statistical test of difference between mean and standard deviation for both Models computed reveal t- statistics range of -20.6 to 1.8 for mean and f- statistics range of 0.005 to 11.5 for standard deviation. Their respective P (probability) - values are less than 0.05, indicating statistically significant difference between mean and standard deviation of the two models. The study reveals that the Simandoux Model has favourable petrophysical parameters indicating higher hydrocarbon potential than the Archie Model. This model could be a valuable tool in a shaly sand environment. Keywords: Hydrocarbon Reservoir, Simandoux and Archie Models, Petrophysical Evaluation