Summary The objective of this work was to identify and quantify important parameters affecting gas production through propped fractures under a non- Darcy gas flow regime. The gas flow capacity of a simulated propped fracture was studied systematically to determine the effects of partial saturation. gel damage, and stress conditions. The flow-capacity response of the 20/40-mesh sand tested throughout this project was affected significantly by variations in the effective gas porosity of the proppant pack. Permeability- and non-Darcy flow characteristics were correlated to effective gas porosity. Partial saturation was found to be a key parameter influencing the permeability and non-Darcy gas flow behavior of a proppant pack. Partially saturated fractures may result from incomplete removal of fracturing fluid, mobility of formation waters. or production of condensates. The partial saturation of the proppant pack, in effect, changes the open porosity available for gas flow, which adversely affects gas permeability and non-Darcy flow parameters. The results from this investigation demonstrate that non-Darcy gas flow behavior through propped fractures in which a saturation phase is present cannot be estimated from results using dry-proppant-pack tests. Introduction The generated equation for linear flow through porous media can be represented by the Forchheimer equation as (1) where -, =pressure gradient, =fluid viscosity, =fluid density, =fluid velocity, =permeability of the porous medium, and =coefficient of inertial resistance or the non-Darcy flow factor. For low fluid velocities, the second term in Eq. 1 becomes negligible, and the equation reduces to Darcy's law. As the velocity of the fluid increases, however, the contribution of the second term to the pressure gradient becomes increasingly significant, especially for low-viscosity fluids. Because gas densities vary with pressure, an integrated form of Eq. 1 that accounts for density variations is generally used to describe the flow of gas through a medium in which the change in gas pressure with flow distance is significant. For example, Dranchuk and Kolada provided a generalized integrated form of Eq. 1 that accounts for Klinkenberg effects at low gas velocities and for variations in gas density with pressure. For characterizing gas flow through proppant packs in the laboratory, however, we can use Eq. 1 while avoiding errors resulting from density and Klinkenberg effects if tests are conducted isothermally and if the mean gas pressure within a proppant pack is maintained at a constant moderate pressure. such as 100 psig [0.69 MPa], throughout each test. A plot of - (L v) vs. pv/ from test data recorded under controlled conditions yields a straight line in which the slope equals the 0 factor and the intercept equals 1/k. Greenberg and Weger found 0 to be independent of pressure for pressures up to 2.000 psi [13.8 MPa] in porous metal. Cooke investigated propped hydraulic fractures and found no appreciable difference in 0 owing to the nature of the test fluid. either brine. gas, or oil. He found that log 0 was inversely proportional to log k for gas flow through stressed sandpacks at irreducible water saturation conditions. Cooke described the fits to his data b), an equation of the form (2) where the constants b and a varied with sand size. Cooke observed that some of his data suggested a slight reduction in inertial resistance with oil or gas flowing at irreducible water saturation compared with brine flow alone, although scatter in the data prevented a clear determination of such an effect. Gewers and Nichols measured, for cores with immobile liquid saturations of up to 30% PV. Their results indicated that gas permeabilities were decreased by immobile partial saturations when compared with dry permeabilities. They found that 3 decreased as saturation increased from 0 to 10% and then increased as saturation increased from 10 to 30 %. They described the decrease in 0 values for low immobile partial saturations as a pore-streamlining effect. Gewers and Nichol found that 0 for carbonate cores containing a partial immobile saturation of up to 30% could be estimated with the correlation of dry-core a vs. k if the effective permeability under saturated conditions was known. For sand proppant packs containing partial saturations, Evans and Evans found that 0 values increased with increasing saturation, whether mobile or immobile, and that the correlations for dry proppants were insufficient for predicting the 0 values of partially saturated proppant packs. Geertsma correlated a wide range of 3, permeability, and porosity data from his work and from the literature. For dry porous media, Geertsma found a general fit to the data by (3) In addition, he hypothesized that, for situations in which an immobile saturation phase is present, (4) where k=gas permeability at 100% gas saturation, SL=saturation-phase fraction, and kr=relative permeability under saturation conditions. Eqs. 3 and 4 are dimensionally correct. Noman et al. used several relationships of 3, k, and 0 to fit data derived from core plugs and reservoir production. They found that the best correlation of their experimental and well test data was obtained by relating beta to () -0.5. The units of ()) -0.5 and 0 are dimensionally equivalent-i. e., cm -which facilitates data comparison. The results from our investigation are correlated with the relation-ships proposed by Cooke, Geertsma, and Noman et al. Experimental Procedures Sandpacks were tested in a 10-in.2 [64.5-CM2] linear-flow conductivity cell at closure stresses from 1.000 to 10,000 psi [6.9 to 69 MPa]. The design of the conductivity cell used in this investigation evolved from the cell Cooke developed that has been widely accepted for proppant conductivity testing. 10–19 Accordingly, the cell has metal walls and makes no provision for leakoff or filtercake effects on test results. Fig. 1 is a schematic of the test system. Throughout the proppant testing program, N, gas was used as the flowing medium to simulate gas production through a propped fracture. The gas pressure was maintained at 100 psig [0.69 MPa] in the center of each test proppant pack to ensure that proper gas density and viscosity values were used in calculations. Gas flow rates through proppant packs were maintained sufficiently high to impose non-Darcy flow conditions. Tests were conducted at room temperature. SPEPE P. 417^
TX 75063-3636, U. S.A.,fax 01-972-952-9435. AbstractThis experimental investigation studied the use of additives to enhance foam properties and improve the in-situ generation of foams for improving gas flooding sweep efficiency. Some of the parameters affecting foam performance were polymer concentration, different surfactants and their concentration, aqueous phase salinity and pH, and effect of ffow rate (or shear rate).Performance of polymer enhanced foams (PEF) was much better when compared to conventional foams. Polyacrylamide polymers were used as an additive. Higher foam resistance and longer foam persistence were achieved by using relatively low concentrations of polymers. The studies also showed that the foam performance was significantly improved over a broad range of polymer concentrations.A number of other investigators have shown that foams are severely affected in the presence of oil. This is especially true of lighter or less viscous oils, and the destabilizing effect is magnified with a higher salinity aqueous phase. PEF with a low salinity aqueous phase showed improvement in foam stability. The effective viscosities of PEF were higher than those of conventional foams with a high salinity aqueous phase and the presence of lighter oils. Further, PEF reduced the negative impact of oils on foam mobility. Of the surfactants studied, alpha olefin sulfonates were tolerant to high salinity brines as well as being compatible with polymer additives. Other surfactants, including amine oxide surfactants, were also studied and showed unusually high foam resistance and stability. Introduction..__ ---_.. Because of recent advances in technology, C02 flooding has become a readily available improved oil recovery method. Significant amounts of residual oil can be recovered by carbon dioxide (COJ flooding. Studies' have shown increasing trends for C02 flood projects in the United States, as well as in other countries. However, many, if not all, gas flooding field projects are often hampered by early C02 breakthrough, poor sweep efficiency, and inefficient oil recovery due to viscous fingering resulted from a low gas phase visco-sity and an unfavorable mobility ratio.Poor sweep efficiency may also be caused by stratification or fracturing. Reservoir heterogeneity, particularly layering, is one of the most important factors that affects C02 flood performance. C02 mobility is usually high relative to that of other reservoir fluids, and the resulting unfavorable mobility ratio enhances fingering that initially results from reservoir heterogeneity or gravity override. In more heterogeneous reservoirs, the C02 floods some layers more easily because of differences in porosity and permeability. In this case, the C02 breaks through faster to the producing wells. More C02 is then required over the lifetime of the ffood, which leads to higher C02 costs per barrel of oil recovered and greater handling and recycle expenses.A need to control gas phase mobility has resulted in many studies of processes which may alleviate the adve...
Formation damage studies using artificially fractured, low-permeability sandstone cores indicate that viscosified fracturing fluids can severely restrict gas flow through these types of narrow fractures. These studies were performed in support of the Department of Energy's Multiwell Experiment (MWX). The MWX program was a coordinated research effort to study methods to evaluate and enhance gas production from low-permeability lenticular reservoirs of the Western United States. Extensive geological and production evaluations at the MWX site indicate that the presence of a natural fracture system is largely responsible for unstimulated gas production. The laboratory formation damage studies were designed to examine changes in cracked core permeability to gas caused by fracturing fluid residues introduced into such narrow fractures during fluid leakoff. Polysaccharide polymers caused significant reduction (up to 95%) to gas flow through cracked cores. Polymer fracturing fluid gels used in this study included hydroxypropyl guar, hydroxyethyl cellulose, and xanthan gum. In contrast, polyacrylamide gels caused little or no reduction in gas flow through cracked cores after liquid cleanup. Other components of fracturing fluids (surfactants, breakers, etc.) caused less damage to gas flows. The results of fluid leakoff tests indicated that polysaccharide polymers caused a filter cake buildup at or near the crack entrance while polyacrylamide polymers did not cause a filtercake buildup within the time period of the tests. For xanthan gum gels filtercake buildup was reduced for gels containing polymer breakers. For gels containing polymer breakers, 100 mesh sand was an effective fluid-loss control agent for narrow fractures. Other factors affecting gas flow through cracked cores were investigated, including the effects of net confining stress and non-Darcy flow parameters. Results are related to some of the problems observed during the stimulation program conducted for the MWX. Introduction The MWX has been an extensive program to characterize and stimulate gas production from low-permeability lenticular gas reservoirs of the Western United States. Three closely spaced wells were drilled into the Cretaceous Mesaverde group in Garfield County near Rifle, Colorado. After extensive geological and geophysical characterization, a series of stimulation treatments were performed in sandstones of the paludal, coastal, and fluvial intervals of the Williams Fork formation at the MWX site. A number of reports have been published which describe the work that has been performed at the MWX site. Core studies indicated that dry core matrix permeabilities to gas at reservoir stress conditions were less than 10 40d and frequently less than 3 40d. At typical levels of water saturation for the reservoir, these values may be reduced by an order of magnitude. Porosities ranged from 3 to 12%. Clays generally averaged less than 10% and were predominantly illite and mixed-layer clays. P. 551^
Laboratory permeability measurements of low permeability (less than 1 md) reservoir rock is significantly affected by test confining pressure. Knowledge of the confining pressure is required to predict permeability at reservoir conditions. A permeability at reservoir conditions. A model is proposed which relates electrical conductivity, permeability, and pore dimensions to confining pressure. The model assumes that rock pores are interconnected by thin cracks and microfractures which can be modeled by rectangular slits. For this model, core permeability is related to confining pressure by a third order polynomial, and electrical conductivity Is polynomial, and electrical conductivity Is related to confining pressure by a first order polynomial, Electrical conductivity and permeability versus confining pressure measurements were made on test cores having laboratory Klinkenberg permeabilities from 20 to 200 microdarcys. The experimental measurements were found to be consistent with the slit model theory. Introduction Thomas and Ward have shown that the measured permeability of many western gas sandstone cores is significantly decreased by increased test confining pressure, whereas effective porosity is only slightly affected. Jones and Owens developed an empirical method for relating permeability to confining pressure which is valid for a variety of low-permeability western gas sandstone core. The results are consistent enough to suggest that a rock matrix model can be developed to relate pore geometry to laboratory permeability. Their studies suggest that low-permeability reservoir rock consists of a matrix material containing larger pores which contribute mostly to the rock porosity. The larger-pores are interconnected by smaller pore throats that restrict permeability and are easily deformed by changes in confining pressure. Wyllie and Gardner developed a capillary model in which pores and pore throats are assumed to be short sections of capillary tubes. Stacking sections of the capillary tubes together in a random manner forms a model which can relate porosity, electrical conductivity, and permeability. porosity, electrical conductivity, and permeability. Archie's equation is often inferred from the Wyllie-Gardner model. It is possible to extend the capillary model to include the effects of confining pressure. The extension is made by assuming that each capillary tube is a thick-walled cylinder to which the confining pressure is applied. As the confining pressure is increased, the inside diameter of the capillary is reduced which reduces the permeability and electrical conductivity. This model could be useful if the pore throats were nearly round capillary tubes. It is more likely that pore throats in low-permeability sands can be described better as slits, cracks or micro-fractures. For the same cross-section area, a slit will be a much weaker structure than a capillary tube and will undergo a larger change in area due to an applied external stress. Our paper proposes that a slit model can paper proposes that a slit model can describe the effect of confining pressure on permeability and electrical conductivity for permeability and electrical conductivity for low permeability reservoir rock. Slit Model Theory The following assumptions have been made for the model:Flow paths through the core are independent and consist of a series of pores connected by rectangular slits.The slits are uniform in size in each flow path.Permeability and electrical conductivity are limited primarily by slit dimensions and fluid properties.Viscous flow is assumed; slit entrance and surface roughness effects are neglected. p. 391
The extent of formation damage due to invasion of fracturing fluids during the hydraulic fracturing process was studied. An apparatus, which can simulate reservoir conditions, is described for measuring permeability before and after fluids are pumped across the surface of a core. Dynamic fluid loss was also measured of fluid which passes through the core plug.
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