2013年7月17日星期三

Porosity in Natural Soils--by GOLD APP INSTRUMENTS

 The porosity of a soil depends on several factors, including (1) packing density, (2) the breadth of the particlesize distribution (polydisperse vs. monodisperse), (3) the shape of particles, and (4) cementing. Mathematically considering an idealized soil of packed uniform spheres, φ must fall between 0.26 and 0.48, depending on the packing. Spheres randomly thrown together will have φ near the middle of this range, typically 0.30 to 0.35. A sand with grains nearly uniform in size (monodisperse) packs to about the same porosity as spheres. In a polydisperse sand, the fit-ting of small grains within the pores between large ones can reduce φ, conceivably below the 0.26 uniform-sphere minimum. Figure 2 illustrates this concept. The particular sort of arrangement required to reduce φ to 0.26 or less is highly improbable, however, so φ also typically falls within the 0.30-0.35 for polydisperse sands. Particles more irregular in shape tend to have larger gaps between their nontouching surfaces, thus forming media of greater porosity. In porous rock such as sand-stone, cementation or welding of particles not only creates pores that are different in shape from those of particulate media, but also reduces the porosity as solid material takes up space that would otherwise be pore space. Porosity in such a case can easily be less than 0.3, even approaching 0. Cementing material can also have the opposite effect. In many soils, clay and organic substances cement particles together into aggregates. An individual aggregate might have a 0.35 porosity within it, but the medium as a whole has additional pore space in the form of gaps between aggregates, so that φ can be 0.5 or greater. Observed porosities can be as great as 0.8 to 0.9 in a peat (extremely high organic matter) soil.

Porosity is often conceptually partitioned into two components, most commonly called textural and structural porosity. The textural component is the value the porosity would have if the arrangement of the particles were random, as described above for granular material without cementing. That is, the textural porosity might be about 0.3 in a granular medium. The structural component represents nonrandom structural influences, including macropores and is arithmetically defined as the difference between the textural porosity and the total porosity.

The texture of the medium relates in a general way to the pore-size distribution, as large particles give rise to large pores between them, and therefore is a major influence on the soil water retention curve. Additionally, the structure of the medium, especially the pervasive-ness of aggregation, shrinkage cracks, worm-holes, etc. substantially influences water retention.



V-Sorb 4800P surface area and particle size analyzer

Technology Articles-BET surface area, BJH pore size distribution, Gas Pycnometer true density: Microporo analysis--by GOLD APP INSTRUMENTS

Technology Articles-BET surface area, BJH pore size distribution, Gas Pycnometer true density: Microporo analysis--by GOLD APP INSTRUMENTS: There are t-plot, HK, SF, DR-plot, NLDFT and GCMC method for the evaluation of micropore. t-plot and DR-plot are used to determine the por...

Microporo analysis--by GOLD APP INSTRUMENTS

There are t-plot, HK, SF, DR-plot, NLDFT and GCMC method for the evaluation of micropore. t-plot and DR-plot are used to determine the pore volume and separation of internal and external surface area of the particle. HK, SF, NLDFT and GCMC method are used to determine the pore size distribution.

Since the micropore analysis theories must describe the short-range interaction of adsorbate and pore wall, it is not as easy as describing the flat surface adsorption or mesopore adsorption. The typical assumption of these theories is that the pore shape is a slit or cylinder. As the parameters, the surface atoms of pore wall and adsorbate molecules must be selected (e.g. oxygen/carbon, N2/Ar). If the sample has uniform and homogeneous pores, the calculated pore size will be accurate. However, most of real materials have nonuniform and heterogeneous pores which are not fit to the assumption of the theories. This disagreement is true not only for the pore size distribution obtained from the gas adsorption but also for other porosimetry and particle size measurement. The gas adsorption so far is the best method for the evaluation of micropores compared to other methods because the probe gas molecule size is below nm to detect micropores.


Our recommend method of micropore analysis is as follows: For zeolitic materials, measure them with the Ar adsorption isotherm at 87K and analyze by the cylindrical pore model theory (SF, NLDFT, and GCMC). N2 molecules, which have strong quadrupole moment, strongly attract to the cation sites and OH group on the surface. For activated carbon materials, they are often measured with N2 adsorption isotherm at 77K and analyzed by the slit pore model theory (HK, NLDFT, and GCMC).








Method of pore size distribution measurement--by GOLD APP INSTRUMENTS

The typical methods to measure the pore size distribution of power and materials are the gas adsorption and mercury porosimetry.

The pore size distribution from the gas adsorption method is commonly analyzed from the nitrogen or Ar adsorption isotherm at their boiling temperature, and it is possible to evaluate the pore size from the molecular size to a few hundred nm. The realistic largest detectable pore size is just over 100nm due to the restriction from the pressure sensor accuracy and temperature stability of coolant. Mercury porosimetry calculates the pore size distribution by pressurizing mercury, which is non-wetting, and measure the corresponding intrusion amount. By this method, it is possible to detect the pore size from a few nm to 1000μm within a short period of time. For the pore size measurement below 10nm, it requires over 140MPa of pressure for the intrusion of mercury, so it is necessary to make sure that the material has the strength to withstand the pressure. Also, by this method, it evaluates the pore size of inkbottle neck (the smallest diameter of the pore) from the principle. The realistic measurement range is from a few 10 nm.

Recently, there are bubble point method and gas permeation method to measure the through pore size of filters and separation membranes.


Determination of pore size distribution

V-Sorb 2800 Instroduction

Technology Articles-BET surface area, BJH pore size distribution, Gas Pycnometer true density: Gas porosity--by Gold APP Instruments

Technology Articles-BET surface area, BJH pore size distribution, Gas Pycnometer true density: Gas porosity--by Gold APP Instruments: Gas porosity  is the fraction of a rock or sediment filled with a gas. Determining the true porosity of a gas filled formation has always...

Gas porosity--by Gold APP Instruments

Gas porosity is the fraction of a rock or sediment filled with a gas.
Determining the true porosity of a gas filled formation has always been a problem in the oil industry. While natural gas is a hydrocarbon, similar to oil, the physical properties of the fluids are very different, making it very hard to correctly quantify the total amount of gas in a formation. Well logging interpretation of the amount of hydrocarbon in the pore space of a formation, relies on the fluid being oil. Gas is light compared to oil causing density logging (gamma ray emitting sensors) based measurements to produce anomalous signals. Similarly, measurements that rely on detecting hydrogen (neutron emitting sensors) can miss detecting or correctly interpreting the presence of gas because of the lower hydrogen concentration in gas, compared to oil.

By properly combining the two erroneous answers from density and neutron logging, it is possible to arrive at a more accurate porosity than would be possible by interpreting each of the measurements separately.


A popular method of obtaining a formation porosity estimate is based on the simultaneous use of neutron and density logs. Under normal logging conditions, the porosity estimates obtained from these tools agree, when plotted on an appropriate lithology and fluid scale. However, in the case of a reservoir where there is gas instead of water or oil in the pore space, the two porosity logs separate, to form what is referred to as gas crossover. Under these conditions, the true formation porosity lies between the measured neutron and density values. Log interpreters often find it difficult to accurately estimate the true formation porosity from these two curves.

Neutron and density logging tools have different responses to the presence of gas in the formation because of differences in the physics of the measurements. A neutron tool response is sensitive mainly to the number of hydrogen atoms in the formation. During the calibration process, water-filled formations are used to develop porosity algorithms, and under these conditions, a lower number of hydrogen atoms is equivalent to a lower porosity. Consequently, when a gas-filled formation is logged, which has a lower number of hydrogen atoms than a water-filled formation of the same porosity, the porosity estimate will be lower than the true porosity.


The density tool, on the other hand, measures the total number of formation electrons. Like the neutron tool, water-filled formations are used in its calibration process. Under these conditions, a lower number of electrons is equivalent to a lower formation density, or a higher formation porosity. Therefore, logging a gas-filled formation, results in a porosity estimate that is higher than the true porosity. Overlaying the neutron and density curves in a gas-bearing zone results in the classic crossover separation.


Technology Articles-BET surface area, BJH pore size distribution, Gas Pycnometer true density: Density Definition and classification

Technology Articles-BET surface area, BJH pore size distribution, Gas Pycnometer true density: Density Definition and classification: Density:   One of the most common density measurements involves the determination of the geometric space occupied within the envelope of ...