Rock permeability

Typical values for sedimentary rock permeability for the flow of hydrocarbons and other fluids are 100 millidarcies (md) or greater. Rocks exhibiting permeabilities of 50 md or less are considered tight, relative to the flow of most fluids. 

Oil recovery can also be affected by extreme variations in rock permeability, such as when high-permeability thief zones between injectors and producers allow most of the injected drive fluid to channel quickly to producers, leaving oil in other zones relatively unrecovered. A need exists for a low-cost fluid that can be injected into such thief zones (from either injectors or producers) to reduce fluid mobility, thus diverting pressure energy into displacing oil from adjacent lower-permeability zones. 

Even in the absence of fractures and thief zones, the volumetric sweep efficiency of injected fluids can be quite low. The poor volumetric sweep efficiency exhibited in waterfloods is related to the mobility ratio, M. This is defined as the mobility of the injected water in the highly flooded (watered-out) low oil saturation zone, m, divided by the mobility of the oil in oil-bearing portions of the reservoir, m, (253,254). The mobility ratio is related to the rock permeability to oil and injected water and to the viscosity of these fluids by the following formula ... 

High pressure equipment has been designed to measure foam mobilities in porous rocks. Simultaneous flow of dense C02 and surfactant solution was established in core samples. The experimental condition of dense CO2 was above critical pressure but below critical temperature. Steady-state CC -foam mobility measurements were carried out with three core samples. Rock Creek sandstone was initially used to measure CO2-foam mobility. Thereafter, extensive further studies have been made with Baker dolomite and Berea sandstone to study the effect of rock permeability. 

In this section the laboratory measurements of CC -foam mobility are presented along with the description of the experimental procedure, the apparatus, and the evaluation of the mobility. The mobility results are shown in the order of the effects of surfactant concentration, CC -foam fraction, and rock permeability. The preparation of the surfactant solution is briefly mentioned in the Effect of Surfactant Concentrations section. A zwitteronic surfactant Varion CAS (ZS) from Sherex (23) and an anionic surfactant Enordet X2001 (AEGS) from Shell were used for this experimental study. 

Effect of Rock Permeability. The effect of rock permeability has been investigated by comparison of mobility measurements made with Baker dolomite and Berea sandstone. Mobility measurements carried out with Rock Creek sandstone (from the Big Injun formation in Roane County, W.Va) is also reported. Rock Creek sandstone has a permeability of 14.8 md. A direct comparison was made with Berea sandstone and Baker dolomite measured with 0.1% AEGS. As mentioned in an earlier section, the permeability of Baker dolomite (a quarried carbonate rock of rather uniform texture with microscopic vugs distributed throughout) was 6.09 md, and of Berea sandstone was 305 md. The single phase permeabilities were measured with 1% brine solution. 

To emphasize the difference between the results in different kinds of rock, it is helpful to consider the relative mobility, Ar, which is the ratio of the measured absolute mobility to the rock permeability. The dimension of relative mobility is reciprocal centipoise, whereas absolute mobility is measured in (md/cp). 

Carbonate rocks consist mostly of calcite and dolomite with minor amounts of clay. The porosity of carbonate rocks ranges from 20 to 50%, but in contrast to sandstone, it tends to decrease with depth. Often, carbonate rocks are fractured, providing a permeability that is much greater than the primary one. In some cases, initial small-scale fractures in calcite and dolomite are enlarged by dissolution during groundwater flow, leading to an increase in rock permeability with time. 

Re-injection into the subsurface is the most often used technique to dispose of geothermal waste heat. The cooled-down fluids, after having fulfilled their tasks in the power generation cycle (or in the direct-use application), can be reinjected into the same geothermal reservoir from which the hot fluid has been produced. The fluid re-injection can help to sustain reservoir pressure, which otherwise would decrease during production. For the re-injection, however, additional wells must be drilled and - if required by the rock permeability at depth - the fluid must... 

Chose factors which directly influence the production, containment, attenuation or migration of leachate. These generally involve the groundwater system, the soil or rock permeability, and the structures within the overburden or rock that control either the direction of movement, rate of movement, or local concentration of fluids. In most cases, landfills or old dumps are located in unconsolidated soils or overburden but occasionally the character of the local bedrock is also significant. 

Two variables are fundamental to assessing the flow across complex fault zones. The first variable is the cumulative fault-rock thickness across the fault zone, i.e., the total thickness of fault-rock from all faults along the flow path. This depends upon the fault frequency along the flow path and is not equivalent to the fault damage zone thickness (cf. Knott, 1993) unless the fault zone is invaded by cements. The second variable is the connectivity of the faults or deformation features with low permeabilities in the fault zone. In the case of a completely connected array with no windows of undeformed material along possible flow paths, the flow is controlled by the permeability of the fault rocks. Where a more open network of faults is present then the flow will depend upon the tortuosity associated with flow around the low permeability zones and the ratio of matrix to fault-rock permeability. The interaction of these two factors will control the effective transmissivity of the zone. We have constructed a database on... 

The increase of the bulk flow beyond the initial intact rock permeability at very low o lo ratios (tests 5 and 12) is not yet fully understood, but could be related to fracturing of the samples perpendicular to the fracture plane at very low confining stresses. 

Estimates of hydrocarbon column height for a range of possible fault rock permeabilities... 

The extent of surface weathering of crystalline rocks or of sedimentary rocks such as shales or carbonates, and thus rock permeability (and yield to wells), decreases rapidly with depth. Also, rock weathering is deeper under valley bottoms than on ridges or hill slopes. This reflects the fact that the weathering, which is facilitated by joints, fractures, and faults, tends to create valley bottoms in the first place. Valley bottoms continue to concentrate runoff (R is then a positive term in the infiltration equation) and so remain the locus of deeper development of secondary rock porosity and permeability and thus of enhanced groundwater storing and transmitting capacity. 

This section discusses polymer rheology, polymer retention in porous media, and rock permeability reduction. 

Permeability reduction, or pore blocking, is caused by polymer adsorption. Therefore, rock permeability is reduced when a polymer solution is flowing through it, compared with the permeability when water is flowing. This permeability reduction is defined by the permeability reduction factor (Fkr) ... 

As discussed earlier, however, polymer adsorption is not a fully irreversible process. Prolonged water injection will reduce the polymer adsorption. Then the rock permeability to the water after polymer flood will not be the same as that to the polymer solution. It will gradually come back to the initial water permeability. In general, Ek < Ek but the process may take many pore volumes of water flush (Gogarty, 1967). 

Zhang, J-.Y., Yang, P.-H., 1998. HPAM molecular weight compatibility with rock permeability. In Gang, Q.-L., et al. (Eds.), Chemical Elooding Symposium—Research Results during the Eighth Five-Year Period (1991-1995), Vol. 1. Petroleum Industry Press, pp. 150-154. 

Model Parameters. Table I lists the model parameters, 18 in all. Those applicable to standard, two-phase flow are shown to the left. They include the absolute rock permeability and porosity, phase viscosities, and Corey exponents and scaling constants for the continuous relative permeabilities. Information on the Boise core, including the relative permeabilities of nitrogen and water, is available from the experiments of Persoff et al. (61). Equations 10 and 11 are fit to those independently measured relative permeabilities. 

Perhaps the most important variable in the description of foam flow through porous rock is the mobility of the foam, the flow achieved for a given pressure drop. This quantity is defined as the simple ratio of the combined superficial flow rate to the imposed pressure gradient. This ratio is indicated in the first part of equation 2, in which the mobility, A, is given in terms of the combined flow rate, Q, the cross-sectional area of the sample, A, the pressure drop, AP, across the sample, and its length, L. As is well known, in the flow of an ordinary fluid through porous media, the mobility can be separated into two factors one has to do primarily with the properties of the rock, and the other, with the properties of the fluid. By using Darcy s relation, the mobility for the ordinary fluid is computed to be the ratio of effective rock permeability, k, to the fluid viscosity, n. 

More recent experiments that were aimed at the selection of a suitable surfactant for use in a southeastern New Mexico oil field have not been so favorable. Apparently, the marked change in effective viscosity with rock permeability, shown in Figure 7, for the obsolete surfactant... 

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