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Showing papers on "Permeability (earth sciences) published in 1975"


Journal ArticleDOI
TL;DR: In this paper, the authors evaluated the general flow properties of coal seams under various conditions of applied axial and radial stress and found that the coal seams were strongly stress dependent decreasing by more than two orders of magnitude in the stress range of 250-2000 psi.

337 citations


Journal ArticleDOI
TL;DR: In this article, the authors used the Hobson equation to estimate pore sizes from mean effective grain sizes of the reservoir and barrier rocks, and then estimated pore and throat sizes as functions of mean effective grains size as based on theoretical packings of grains.
Abstract: Capillary pressures between oil and water in rock pores are responsible for trapping oil, and the height of oil column, zo, in a reservoir may be calculated from the Hobson equation modified as follows: [EQUATION] where ^ggr is the interfacial tension between oil and water, rt is the radius of pore throats in the barrier rock, rp is the radius of pores in the reservoir rock, g is acceleration of gravity, and ^rgrw and ^rgro are the densities of water and oil, respectively, under subsurface conditions. To apply the equation, pore sizes must be estimated from mean effective grain sizes of the reservoir and barrier rocks. Effective grain size, De, in centimeters can be approximated from core analysis data by means of an empirical permeability equation from which [EQUATION] where n is porosity in percent and k is permeability in milli-darcys. Then pore and throat sizes may be estimated as functions of mean effective grain size as based on theoretical packings of grains. The oil-column equation assumes hydrostatic conditions, and additional column, ^Dgrzo, may be trapped if hydrodynamic flow occurs down the dip from barrier to reservoir facies, or [EQUATION] where dh/dx is the potentiometric gradient and xo is the width of the oil accumulation. Calculations of oil columns in stratigraphic fields show that the equations give values which are in fair to good agreement with observed oil columns; that porous and permeable, very fine-grained sandstones and siltstones are commonly effective barriers to oil migration; and that the recognition of such barriers can be important in exploration for stratigraphic traps.

335 citations


Journal ArticleDOI
TL;DR: In this paper, the authors measured the permeability of the Berea Sandstone as a function of both confining pressure and pore pressure and found that the pore fluid has a higher compressibility than the granular framework which supports externally applied stresses.
Abstract: Permeability of the Berea Sandstone was measured as a function of both confining pressure and pore pressure. As expected, permeability decreased with increased confining pressure and increased with increasing pore pressure. However, pore pressure had a significantly larger effect on permeability than did confining pressure. This behavior can be explained if the matrix through which the pore fluid flows has a higher compressibility than the granular framework which supports externally applied stresses.

210 citations


Journal ArticleDOI
TL;DR: In this article, a large number of natural marine sediment samples from the Gulf of Mexico were determined through the use of laboratory consolidation tests and a statistical analysis of the natural log of permeability versus porosity was used to develop the permeability prediction equation for each of the groups listed.
Abstract: Permeability of a large number of natural marine sediment samples from the Gulf of Mexico was determined through the use of laboratory consolidation tests. The samples were divided into the following groups: Group 1, sediment consisting of more than 80% clay (material 2 μm or less in size); Group 2, sediment containing from 60 to 80% clay‐size material; Group 3, silty clays with less than 60% clay; and Group 4, silts and clays that have a significant sand‐size fraction present (more than 5% sand). The permeabilities of the groups ranged from 10−5 to 10−10 cm/s with 35% normal seawater being used as the saturating fluid. A statistical analysis of the natural log of permeability versus porosity was used to develop the permeability prediction equation for each of the groups listed. The equation for Group 1 is k =en(15.05)‐27.37. for Group 2, k=en(14. 18)‐26.50. for Group 3, k= en(15.59)‐26.65. for Group 4 k=en(17.51)‐26.93.and for all data, k = en(14.30)‐26.30; wherc n is the porosity (in decimals) and k is the coefficient of permeability. These equations are useful for predicting changes in permeability with depth in fine‐grained sediments of the Gulf of Mexico. The ability to predict permeability in a continuous sequence, where the deposition history is known, may explain the large variations that we see in the physical properties in sediments similar in grain size and mineralogy.

132 citations


Journal ArticleDOI
TL;DR: In this paper, a natural snowpack with ice layers is described in terms of an equivalent anisotropic porous medium, represented as a diagonalized matrix whose principal values can be calculated from a small amount of information about the prototype snowpack.
Abstract: A natural snowpack with ice layers is described in terms of an equivalent anisotropic porous medium. The anisotropic permeability is represented as a diagonalized matrix whose principal values can be calculated from a small amount of information about the prototype snowpack. Ice layers increase the transit time for water movement by a factor equal to the ratio of the principal values of permeability. The flow path, volume flux, and wave speed are determined by the slope of the snowpack and principal values of permeability. When a snowpack is assumed to be isotropic, the error in calculating transit time increases with the difference between the principal values of permeability. Usual variations in slope introduce a small change in the transit time.

90 citations


Journal ArticleDOI
TL;DR: In this paper, the effect of temperature on absolute and relative permeability of core samples was investigated for six Boise sandstone samples and two Berea sandstone sample sets at room temperature and at 175/sup 0/F, respectively.
Abstract: Equipment was constructed to perform dynamic displacement experiments on small core samples under conditions of elevated temperature. Oil-water flowing fraction and pressure drop were recorded continuously for calculation of both the relative permeability ratio and the individual relative permeabilities. Imbibition relative permeabilities were measured for five samples of Boise sandstone at room temperature and at 175/sup 0/F. The fluids used were distilled water and a white mineral oil. The effect of temperature on absolute permeability was investigated for six Boise sandstone samples and two Berea sandstone samples. Results for all samples were similar. The irreducible water saturation increased significantly, while the residual oil saturation decreased significantly with temperature increase. The individual relaive permeability to oil increased for all water saturations. The individual relative permeability to water decreased with temperature increase for water saturations below the room-temperature residual oil saturation, but the relative permeability to water at flood-out increased with temperature increase. Absolute permeability decreased with temperature increase.

88 citations


Journal ArticleDOI
TL;DR: For example, it is known that most petroleum is generated at temperatures between 60 and 150°C, corresponding to depths of burial of 1,500 to 4,500 m as discussed by the authors.
Abstract: It is now generally believed that most petroleum is generated at temperatures between 60 and 150°C, corresponding to depths of burial of 1,500 to 4,500 m. At these depths shale source rocks have lost most of their water and practically all their permeability. If a good source rock still contains 500 ppm hydrocarbon, it probably has expelled a similar amount. If such a rock was subjected to a porosity loss of 10 percent during the time that it gave up 500 ppm by weight, the ratio of hydrocarbons to hydrocarbons plus liquid is 12,000 ppm, or 1.2 percent by volume of the liquid. There is no possibility of dissolving this much oil in water, even with the aid of solubilizers. Much of the shale surface may be wetted by oil, so that the saturation at which oil will flow as a continuous phase may be less than 10 percent. Furthermore, much of the water in the pores is structured and may behave like a solid. For fluid flow it might be considered as part of the solid matrix, and oil then would form a large fraction of the pore liquid. The relative permeability of the shale to oil then would become greater than to water. As compaction of the source rocks proceeds, shales might expel oil preferentially to water.

83 citations



Patent
31 Oct 1975
TL;DR: In this paper, a gaseous substance is injected into the upper high permeability strata to increase the pressure therein sufficiently to displace the mixture of viscous petroleum and solvent downward into the lower high-papernot strata, wherein it is displaced horizontally to a remotely located well for recovery to the surface of the earth.
Abstract: Recovery of viscous petroleum from thick formations is especially difficult because thermal fluids or solvents needed to mobilize the viscous petroleum tend to channel through high permeability streaks in the formation, thereby bypassing large portions of the petroleum saturated formation. By forming or ensuring that there are naturally occurring high permeability strata in the upper portion and in the lower portion of the petroleum formation, and establishing separate communication means between the surface of the earth and the upper and lower high permeability strata, effective downward displacement may be achieved. A heated fluid such as steam is injected into one well in fluid communication with the lower high permeability strata to pass horizontally through the high permeability strata to another well which is also in fluid communication with the lower high permeability strata, sufficient to heat the lower high permeability zone to a temperature substantially above the ambient temperature of the formation. A solvent having a boiling point intermediate between the ambient temperature of the formation and the temperature to which the communication path is heated is injected into the heated communication path. The solvent vaporizes and moves up into the formation immediately thereabove to dissolve into the viscous petroleum. A gaseous substance is then injected into the upper high permeability strata to increase the pressure therein sufficiently to displace the mixture of viscous petroleum and solvent downward into the lower high permeability strata, wherein it is displaced horizontally to a remotely located well for recovery to the surface of the earth.

49 citations


Journal ArticleDOI
P.J. Clossman1
TL;DR: In this paper, a model for describing aquifer influx in a fissured reservoir was developed, which includes petrophysical properties of good and poor rock, as well as fissure parameters.
Abstract: A model has been developed for describing aquifer influx in a fissured reservoir. This model includes petrophysical properties of good and poor rock, as well as fissure parameters. For the applications considered thus far, it has been found that flow in the fissures dominates the aquifer performance and that rock properties and spacing between fissures are of lesser importance. For a given aquifer, the fissure permeability and fissure volume fraction appear to be important parameters, as are rock permeability and porosity in cases of a high percentage of poor rock.

46 citations


Journal ArticleDOI
TL;DR: In this article, trapped gas saturation values in selected carbonate reservoirs were investigated, and samples covering the porosity and permeability range within each field were tested Cores from Smackover reservoirs located within 4 states were included to examine differences in trapped gas which might occur within a carbonate deposited over a large geographical area The trapped gas varied with initial gas in place and with rock type.
Abstract: Trapped gas saturations existing after gas displacement by wetting phase imbibition are presented for selected carbonate reservoirs Formations representing various rock types were investigated, and samples covering the porosity and permeability range within each field were tested Cores from Smackover reservoirs located within 4 states were included to examine differences in trapped gas which might occur within a carbonate deposited over a large geographical area The trapped gas varied with initial gas in place and with rock type With gas in place of 80% of pore space, trapped gas values ranged from a low of 23% of pore space in Type II chalk to a maximum of 69% in the Type I limestone evaluated Correlation of trapped gas saturation values was attempted using several approaches, but none was entirely satisfactory No relationship with permeability was found within most reservoirs, or between different reservoirs Within a given field, trapped gas at a common initial gas saturation typically increased as porosity decreased

Journal ArticleDOI
TL;DR: In this article, the upconing of saline water in response to pumping from an overlying layer of fresh water is investigated by numerical integration of the governing differential equation, and the transition zone between the fresh and saline water is idealized as an abrupt interface.
Abstract: The upconing of saline water in response to pumping from an overlying layer of fresh water is investigated by numerical integration of the governing differential equation. The transition zone between the fresh and saline water is idealized as an abrupt interface. Full consideration of the nonlinear boundary conditions on the water table and interface surfaces is included for steady flow toward partially penetrating pumping wells in both isotropic and anisotropic aquifers. There exists an optimum well penetration into the fresh-water layer which permits maximum discharge without salt-water entrainment. The optimum penetration increases as the vertical permeability is reduced relative to the horizontal permeability. The maximum well discharge obtainable without salt-water entrainment is greater for aquifers with a reduced vertical permeability than for isotropic aquifers, a result that contrasts with previously published conclusions. Previous analyses which linearize the boundary condition on the interface overestimate the critical discharge.

Journal ArticleDOI
TL;DR: In this paper, the classic equations of Washburn and Rideal for the rate of penetration of a fluid into a capillary due to surface tension are re-examined and time-dependent solutions are obtained for large times in both horizontal and vertical flow.
Abstract: The classic equations of Washburn and Rideal for the rate of penetration of a fluid into a capillary due to surface tension are re-examined and time-dependent solutions are obtained for large times in both horizontal and vertical flow. By applying Darcy's law, a general theory of wetting of a porous medium is derived. The rate of fluid penetration is expressed in a form analogous to that for a capillary, in terms of fluid viscosity, surface tension, porosity and permeability. The permeability is calculated for the Happel–Kuwabara cell model of a porous medium, consisting of a swarm of identical spherical particles.


Journal ArticleDOI
TL;DR: Experimental and numerical coning studies were made of water coning into an oil-producing well under 2-phase, immiscible, and incompressible flow as mentioned in this paper, and the model chosen was a pie-shaped, cylindrical model having radial symmetry.
Abstract: Experimental and numerical coning studies were made of water coning into an oil-producing well under 2-phase, immiscible, and incompressible flow. The model chosen was a pie-shaped, cylindrical model having radial symmetry. In the laboratory experiment, saturations were measured in situ by 70 microresistivity probes embedded in the sand pack. Results indicate that the numerical model can adequately simulate the experiment. Increasing the production rate or the well-bore penetration leads to earlier water break-through; the higher the ratio of gravity to viscous forces, the greater is the oil recovery at any given water-oil ratio. Wells should be spaced closer if the horizontal permeability is low or the vertical permeability is high. High vertical permeability decreases the oil recovery, while the opposite holds true for horizontal permeability. In stratified formation, highest oil recovery results if the most permeable section is the top of the oil-bearing zone.



Journal ArticleDOI
TL;DR: In this article, the correlation between the permeability and the strength of concrete was studied by means of new methods of measuring the air and water in concrete. But the scatter of the results is rather large, probably due to the heterogeneous character of concrete containing aggregate particles which are large in comparison with the test cavity.




Journal ArticleDOI
TL;DR: The results of this investigation would tend to substantiate the need for special spruing and venting procedures on relatively impermeable investments unless used in high concentration.
Abstract: Permeability of various gypsum- and phosphate-bonded investments was measured during conventional burn-out procedures Porosity determinations were made on specimens cooled to room temperature after burn-out As a group, the gypsum-bonded investments were found to be more permeable than the phosphate-bonded investments Two phosphate-bonded investments were determined to be relatively impermeable to gas flow, while another exhibited permeability comparable to that of the gypsum-bonded investments In spite of differences in permeability, the porosity of each type of investment was nearly constant The porosity of the phosphate-bonded investment was approximately three-fourths that of the gypsum investments These investments were modified by the addition of varying amounts of acrylic polymer for the purpose of altering permeability The addition of acrylic polymer increased porosity and permeability of all of the materials included in this investigation The acrylic additives, however, had no effect on the permeability of relatively impermeable investments unless used in high concentration The results of this investigation would tend to substantiate the need for special spruing and venting procedures

ReportDOI
01 Nov 1975
TL;DR: In this paper, the authors investigated the feasibility of extracting geothermal energy from dry hot rock by creating a hydraulic fracture in hot, impermeable rock, where heat will be exchanged subsequently at the fracture surface between the rock and a circulating fluid.
Abstract: The Los Alamos Scientific Laboratory is currently conducting a study to determine the feasibility to extract geothermal energy from dry hot rock. The investigated concept calls for the creation of a hydraulic fracture in hot, impermeable rock. Heat will be exchanged subsequently at the fracture surface between the rock and a circulating fluid. The successful creation of hydraulic fractures in the granitic section of exploratory holes GT-1 and GT-2 yielded sufficient data to calculate the average permeability of the rock next to a fracture by means of the mathematical model. The calculated permeabilities were found to be in the microdarcy range and proved the granitic rock penetrated by GT-1 and GT-2 to be sufficiently impermeable to test the above concept. (auth)

Journal ArticleDOI
TL;DR: In this paper, a small sinusoidal component was added to the Helmholtz resonance of an empty narrow necked vessel to superimpose atmospheric pressure within the vessel and the damping of this sinusoid component on the introduction of a sand layer into the vessel was determined.





01 Jan 1975
TL;DR: A study of the environmental effects of power production from geopressured reservoirs reveals two important problems that cannot be adequately evaluated at this time: surfaces subsidence and the possible inducement of earthquakes, which could result from the efficient production of power over the lifetime of a reservoir as mentioned in this paper.
Abstract: A study of the environmental effects of power production from geopressured reservoirs reveals two important problems that cannot be adequately evaluated at this time: surfaces subsidence and the possible inducement of earthquakes, which could result from the efficient production of power over the lifetime of a reservoir. These effects must be considered in any environmental impact statement and must be monitored over the entire lifetime of a production facility. A particular reservoir in northwest Cameron County, Texas, was used as a model. Pertinent parameters are as follows: Depth of sand 14,300-15,000 ft; Thickness 700 ft; Temperature 320°F; Reservoir pressure (ave.) 12,000 psi; Total salinity 2,000-6,000 ppm; Permeability 0.10-0.14 Darcy; Porosity 0.25; Area of reservoir 300 mi{sup 2} or more; Well-head pressure 5,000 psi or more. Environmental studies were based upon the properties and location of this model reservoir. (4 figs., 4 refs.)

Proceedings ArticleDOI
Alfred R. Jennings1
01 Jan 1975
TL;DR: In this article, the authors investigated the behavior of fluid flow on formation core plugs that have been subjected to either aqueous base fluids or hydrocarbon fluids containing various types of oil-wetting or water-wetting surfactants.
Abstract: The use of surfactants during various types of fracturing and acidizing treatments on oil wells is a commonly accepted practice. It is known and has been verified by several laboratory studies that surfactants have a marked effect on formation rock permeability in the treated wells. During hydraulic fracturing treatments, for example, large volumes of surfactant-bearing fluids are pumped deep into the formation matrix through the created fracture system. The results are presented of an investigation of the behavior of fluid flow on formation core plugs that have been subjected to either aqueous base fluids or hydrocarbon fluids containing various types of oil-wetting or water-wetting surfactants. Guide lines as to the most efficient types of workover fluid and surfactant combinations for maintaining hydrocarbon permeability are indicated from the data obtained. A method of water-block removal and restoring formation hydrocarbon permeability also has been observed and is discussed.