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Porosity is the best known physical characteristic of an oil reservoir. It determines the volume of oil or gas present, and all recovery computations must be based on knowledge of its value. Porosity of a material is defined as that fraction of the bulk volume of this material that is not occupied by the solid framework of the material. In oil reservoirs, the porosity represents the percentage of the total space that is available for occupancy by either liquids or gases. It determines the storage capacity of the sand and is generally expressed on a percentage basis or as a fraction or a decimal. One may distinguish two types of porosity, namely, absolute and effective: Absolute porosity is the percentage of total void space with respect to the bulk volume regardless of the interconnection of the pore voids.
Effective porosity is the percentage of interconnected void space with respect to the bulk volume. Grain volume methods: In these methods the consolidated sample is solvent extracted and dried; the bulk volume is determined either by the displacement of a liquid which does not penetrate the sample or by saturating the sample and volumetric ally displacing a suitable liquid with the saturated sample. The grain volume, or volume of the solid framework of the sample, maybe measured by the volumetric displacement of a gas or a liquid, while the pore volume may be measured by determining the amount of liquid necessary to saturate the sample. It is obvious that the percentage of porosity may be calculated from such data by use of either of the two following relationships: Per cent porosity = 100 x (bulk volume - grain volume / bulk volume) Per cent porosity = 100 x (pore volume / bulk volume) Bulk volume determination: The bulk volume of the extracted and dried samples may be determined by volumetric displacement of mercury. Pore gas expansion method: The measurements of porosity may also be made by the pore-gas expansion method, or so-called Washburn-Bunting method. (1922). This method makes use of a modified Toepler pump so much in use in high-vacuum techniques in order to produce the barometric vacuum and remove air from a dried core.
The bulk volume of the core must be known from other tests. Mercury-injection method: When a rock has a very small fraction of void space, it is difficult to measure it by methods previously discussed. One may then resort to forcing a non compressible liquid into the sample under very high pressure. The original idea appears to have been that of Horner (1944). Loss of weight method: The measurement of the grain volume of a core sample may also be determined by the loss in weight of a saturated sample plunged in a liquid. Liquid saturation Method: Measurements of pore volume may also be achieved by liquid saturation.
Porosity of large core samples: A technique is advocated by Locke and Bliss (1950) for the measurement of porosity in large cores, i. e, cores as recovered from drilling operations without further reduction in size by sampling of small plugs. Absolute Porosity Measurement: In the determination of absolute porosity, it is required that all non connecting as well as interconnecting pores be accounted for. Methods for the determination of reservoir fluid saturation's in place consist in analyzing reservoir core samples for water and oil, the saturation in gas being obtained by difference since the sum of the saturation's in the three fluids is equal to unity. As a general practice a simple procedure is to determine the water saturation of a sample by a suitable technique and then to measure the total loss of weight of the sample on extraction and drying. The quantity of oil present is then calculated by subtracting the weight of water found from the total loss in weight.
The methods which may be recommended for this determination will be discussed briefly. Distillation method: Water saturation may be determined by distillation methods such as the ASTM method and the Dean and Stark method. Critical solution temperature method: A fluid saturation method which makes use of the critical solution temperature has been described by Taylor (1938). Titration method: Another procedure for saturation determination makes use of the titration method. Retort method: the procedures discussed above are nearly all combinations or modifications of methods previously described in the availble literature which have been found satisfactory in handling a great variety of core samples with various requirements of rapidity and accuracy. Other methods have been tested and found to be less desirable, such as the retort method (Yuster and Levine, 1938).
The main objection to the retort method, still in common use, is the cracking of the oil with the relating production of gases and the possibility of driving out water of crystallization. Capillary pressure method: In view of the difficulties involved in fluid saturation determinations from cores, Thornton and Marshall (1947) have proposed the use of capillary pressure curves (capillary suction vs. brine saturation) as a substitute for the direct measurements of connate water. The procedure involves the determination of air-water capillary pressure curves on selected core samples, the determination of the distance above water-oil contact at which the samples were secured, and the application of a correction in order to reduce the air-water capillary pressure curve to an oil-water capillary pressure.
Summarizing, fluid saturation determinations are probably the least reliable of the measurements performed on reservoir rock samples. Perhaps the best approach to a true solution of the problem is by correlation of quantitative information from various independent measuring means, to of which have been reviewed before, namely, by direct measurements of core samples and by indirect measurements through the use of capillary pressure curves. Bibliography:
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Research essay sample on Fluid Saturation Determinations Capillary Pressure Curves Volume
