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^
In laboratory measurements of relative permeability, capillary discontinuities at sample ends give rise to capillary end-effects. End-effects influence fluid flow and retention. If end-effect artifacts are not minimized by test design and data interpretation, relative permeability results may be significantly erroneous. This is a well known issue in unsteady-state tests, but even steady-state relative permeability results are influenced by end-effect artifacts. This work describes "The Intercept Method," a novel modified steady-state approach, in which corrections for end-effect artifacts are applied as data is measured.The intercept method requires running a steady state relative permeability test with several different flow rates for each fractional flow. Obtaining multiple (3-4) sets of rates (Q), pressure drops (⌬P), and saturation data allow for assessment of capillary end effect artifacts. With Darcy flow, a plot of pressure drop versus total flow rate is typically linear. A non-zero intercept or offset is an end-effect artifact. To correct for the effect, the offset is subtracted from measured pressure drops. Corrected pressure drops are used in permeability calculations. The set of saturations from measurements at the target fractional flow are used to calculate a corrected final saturation. Because corrections for end effects are made during the test rather than after the test is over, any discrepancies can be resolved by additional measurements before moving on to the next fractional flow. Rates are then adjusted to yield the next target fractional flow condition and the same protocol is repeated for each subsequent steady-state measurement. The method is validated by theory and is easy to apply.
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^
The use of vibration to improve oil recovery has long been investigated. The background for this novel technology is reviewed along with the project rationalizations, designs considerations, and measurements performed in advance of a downhole vibration stimulation field test. This field demonstration will pilot test the potential of downhole vibration to enhance oil recovery from a shallow oilfield in Osage County, Oklahoma. The project is supported by the Department of Energy (DOE), Seismic Recovery LLC, Phillips Petroleum Co., and Grand Resources, Inc. Recent literature has reported successful vibration stimulation in shallow reservoirs with high water oil ratios (WOR). Osage County has, like many areas of the United States, numerous old fields under waterflood, with many wells producing marginal oil with substantial water production. Introduction When wells in waterflooded fields are abandoned due to high water-cut, often there are still significant amounts of oil trapped in the formation, although production is not economical. Vibration stimulation is a possible method for improving oil production and increasing ultimate economic recovery in these situations. The vibration force introduced in the reservoir is thought to facilitate the movement of oil in one or more ways: by diminishing capillary forces; reducing adhesion between the rock and fluids; or causing oil droplets to cluster into "streams" that flow with the waterflood. Significance of Vibration Stimulation. The ability to generate sufficient downhole vibration energy to improve flow characteristics is a very intriguing concept. The economic potential for vibration stimulation for enhanced oil recovery is truly staggering. The Interstate Oil and Gas Compact Commission reported in 1995, "immobile oil is held in reservoirs by viscous and capillary forces&. Only a small amount of immobile oil can be recovered by conventional primary and secondary techniques. Instead, the 238 billion -bbls immobile oil reserve (U.S.) is the target for enhanced oil recovery techniques."1 Vibration stimulation has the capability to shift the relative permeability curve and, as an enhanced oil recovery technology, increase recovery of "immobile oil reserves." Vibration Stimulation Historical Background Russian Investigations. The interest in elastic-wave vibration stimulation (as opposed to non-elastic vibration, such as explosions) goes back to the 1950s. This interest is well documented in the paper by Beresnev and Johnson, in which the authors reported on the full spectrum of investigative work in both the USSR and USA.2 They review the efforts of over a hundred researchers probing the effects of man-made vibrations from the ultra sound range of 5 MHz to barely audible, low end of 1 Hz including traffic induced seismic stimulation. The effects of earthquakes on oil production were also reviewed, however the results of conventional and nuclear explosions were not.
Summary In laboratory measurements of relative permeability, capillary discontinuities at sample ends give rise to capillary end effects (CEEs). End effects affect fluid flow and retention. If end-effect artifacts are not minimized by test design and data interpretation, relative permeability results may be significantly erroneous. This is a well-known issue in unsteady-state tests, but even steady-state relative permeability results are influenced by end-effect artifacts. This work describes the intercept method, a novel modified steady-state approach in which corrections for end-effect artifacts are applied as data are measured. The intercept method requires running a steady-state relative permeability test with several different flow rates for each fractional flow. Obtaining multiple (three or four) sets of rates (Q), pressure drops (ΔP), and saturation data allows for assessment of CEE artifacts. With Darcy flow, a plot of pressure drop vs. total flow rate is typically linear. A nonzero intercept or offset is an end-effect artifact. To correct for the effect, the offset is subtracted from measured pressure drops. Corrected pressure drops are used in permeability calculations. The set of saturations from measurements at the target fractional flow is used to calculate a corrected final saturation. Because corrections for end effects are made during the test rather than after the test is complete, any discrepancies can be resolved by additional measurements before moving on to the next fractional flow. Rates are then adjusted to yield the next target fractional-flow condition, and the same protocol is repeated for each subsequent steady-state measurement. The method is validated by theory and is easy to apply.
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