Capillary End Effect Research Articles

Applications Rheology of Foam Iin Porous Media At the Limiting Capillary Pressure

Recent research suggests that, for some strongfoams, foam texture, which controls foam rheology, is in turn closely controlled by capillary pressure pc. In particular, at steady state these foams flow under conditions in which pc is nearly constant at the limiting capillary pressurepc*, water saturation and water relative permeability are virtually invariant, and the pressure gradient is proportional to water flow rate and independent of gas flow rate. This report examines some implications of these statements for cases of steady foam flow. In steady, 1D radial flow without phase change, this hypothesis implies that foam behaves as a Newtonian fluid, even though foam rheology at constant texture is strongly non-Newtonian. In a steamflood, however, evaporation of water as pressure declines in flow from an injection well could make foam appear to be shear-thickening. Complete plugging cannot occur at steady-state in a foam at pc*. Temporary plugging is possible, however, with the duration of plugging governed by the rate of water transport and rise of capillary pressure. The capillary end effect can strongly affect coreflood results at low pressure gradient. Diversion between layers differing in permeability depends on contact between the layers. If two layers are separated by an impermeable barrier, then limited data on the effect of permeability on pc* suggests there is diversion of flow into the low-permeability layer. However, if the layers are in capillary equilibrium, the difference in pc* between layers can mean virtually complete flow diversion into the high-permeability layer.

Relative Permeabilities From Centrifuge Data

Abstract The drainage of a wetting phase (say oil) by a non-wetting phase (say gas) may be simulated in the centrifuge by two liquids. Such experiments were conducted on a number of cores and they are discussed in a paper by Firoozabadi, et al.(1). In this paper we consider two of the cores with available capillary pressure data. Two forms of the relative permeability models are selected and the parameters of these models are obtained by history matching with a numerical simulator developed for this study that properly accounts for the capillary pressure and the boundary conditions in centrifuge experiments. It is shown that:recoveries can be matched with two — and maybe even more — very different sets of relative permeability curves;recoveries are sensitive to the parameters of each relative permeability model; andlate time predictions can be improved by using a linear relationship for the wetting phase relative permeability below some arbitrary value of the wetting phase saturation. It is concluded that both wetting and non-welling phase permeabilities can be estimated from a least-squares history match of the recovery data. However, for the oil-water system examined in this paper, the history match technique leads to a non-unique set of relative permeabilities. Introduction Relative permeability curves for a given rock sample may be measured from the steady-state or unsteady-state core displacement experiments. The steady-state(2) method requires simple calculations to derive relative permeabilities from experimental data. Either explicit or implicit approaches can be used to calculate relative permeabilities from the unsteady-state core flooding experiments. The Johnson, Bossler and Naumann(3) (JBN) or its modification(4) are explicit techniques. In the implicit method, relative permeability curves are adjusted so that the response simulated by a numerical model of the displacement process matches the measured quantities(5,6). The explicit JBN approach relates phase permeabilities and saturations at the effluent-end or some other point in the core. Relative permeabilities derived from the JBN method normally cover only a part of the saturation range over which both phases are mobile. The application of this method may yield anomalous relative permeability curve shapes for typical heterogeneous carbonate core samples and for strongly water-wet homogeneous cores(5,6). The JBN technique, however, seems to be valid for the conditions assumed in its development. A basic assumption of this method is that the capillary pressure and hence the capillary pressure end effects can be ignored. This is realized in practice by conducting experiments at sufficiently high flow rates. However, for many field scale calculations the flow rates are such that the inclusion of the capillary pressure is necessary. Also in heterogeneous cores, effective average relative permeabilities may be rate sensitive(7) and therefore the standard JBN method cannot be used. Archer and Wong(5) suggested that the use of a reservoir simulator to model laboratory tests can smooth the anomalous relative permeability curves obtained from the JBN method. They agreed that the smoothed curves reflect properties that are more consistent with the bulk behavior of the core sample than the results obtained from the standard JBN method.

Three-Phase Relative Permeability of Berea Sandstone

Summary Reservoir engineering calculations frequently require consideration ofcoexisting oil, water, and gas phases. Such three-phase flow occurs when oil isdisplaced by simultaneous gas/water flow as in CO2, water-alternating-gasflooding, steamflooding, or other enhanced recovery processes. For this reason, reservoir simulators generally include three-phase relative permeabilityprediction methods. Two- and three-phase relative permeabilities were measuredon a water-wet fired Berea sandstone core with a fully automated steady-statemethod to investigate prediction methods experimentally. Introduction Reservoir studies often require use of three-phase relative permeabilitiesbecause of the presence of both water and gas in oil reservoirs, but laboratorymeasurement is almost prohibitively difficult. To resolve this problem, Stonesuggested two prediction methods that approximate three-phase relativepermeabilities from the more readily available two-phase data. His methods havebeen used widely, but with some skepticism, to estimate three-phase relativepermeabilities. Controversy exists about which method to use becausepredictions with the two methods differ significantly. When Stone introducedhis second method (Method 2), he reported that it gave better agreement withthen-available experimental data than his earlier method (Method 1) did. Later, Saraf et al. measured three-phase relative permeabilities for fired Bereasandstone and compared the data with predictions from Stone's methods. Theyreported that Method 1 was better than Method 2 in low oil-saturation ranges.while Method 2 was better in high oil-saturation ranges. Neither method, however, predicts oil relative permeabilities that are reasonably close totheir experimentally determined values. Van Spronsen reported that oil isoperms(saturation contours of equal relative permeability) predicted by Stone'sMethod 2 are convex, whereas their experimental isoperms (measured by acentrifuge method) are concave when viewed from the oil apex of the saturationternary diagram. Using a computer plotting program to improve the data fit. Fayers and Matthews tested the two methods against selected publishedexperimental data. They concluded that Method 1 was superior to Method 2. Bakerextensively re-evaluated the relationships between two- and three-phaserelative permeabilities of published data and concluded that a simple linearinterpolation of two-phase data works as well as, or better than any othercurrently available method. Current methods of estimating three-phase relativepermeabilities are uncertain and require further experimental verification. Such verification needs accurate experimental data for both two- andthree-phase relative permeabilities. Special consideration should be given tothe effects of saturation history in three-phase flow. Investigators have madeexperimental measurements of three-phase relative permeabilities since Leverettand Lewis reported their three-phase-study results. Compared with the enormousnumber of two-phase-flow studies, the relatively small number of three-phasestudies highlights the difficulties in experimental determination ofthree-phase relative permeabilities. Table 1 summarizes the experimentalstudies, listing reported core materials, saturation histories, experimentalmethods, and types of isoperm curves. Refs. 3, 16, and 17 provide detailedreviews with discussions on factors affecting experimental measurements (suchas capillary end effects). Previous experimental studies reported mostlyincomplete two-phase relative permeability data. Saraf et al. reportedextensive two-phase data, but the two-phase relative permeabilities are notconsistent with the isoperms reported in their three-phase ternary diagrams. Stone, Fayers and Matthews, and Baker supplemented the missing two-phase databy estimation and with some necessary assumptions from other reported two-phasedata or from isoperms in the ternary diagrams. Relative permeability depends onfluid saturation and on the saturation history. Most previous experimentalstudies either have ignored or incompletely reported saturation-historyeffects. From the experimental procedures reported, previous studies can begrouped into three saturation-history cases: primary DDI, secondary DDI, andIDI (see Table 1). Here, Saraf et al. nomenclature (i.e., D=decreasing andI=increasing) is adopted to name the saturation histories. For instance, DDIindicates the case of water saturation decreasing, oil saturation decreasing, and gas saturation increasing. IDI indicates the case of water saturationincreasing, oil saturation decreasing, and gas saturation increasing. JPT P. 1054⁁

A Comparison Of Steady-State And Unsteady-State Relative Permeabilities Of Viscocities Oil And Water In Ottawa Sand

Abstract Relative permeabilities have a central role in numerical simulation of oil recovery processes. Reliable relative permeability data for heavy oil reservoirs are scarce because of the experimental difficulties involved in working with heavy oil systems at reservoir conditions. Often, in computer simulation studies, the laboratory measured relative permeabilities fail to provide satisfactory history march of field operation. While there are several reasons for such failures, including the difficulties in obtaining a representative sample of the reservoir material and differences between hydrodyna1n1e conditions used in the laboratory measurements and the actual reservoir conditions, the experimental errors in relative permeability measurements may be a principal cause. There appears to be lack of consensus among different laboratories on how relative permeabilities should be measured in heavy oil systems. The measurement techniques currently being used were developed for light oil systems and fail to address experimental problems which are peculiar to heavy oil systems. For example, viscous fingering is rarely a concern in light oil systems but becomes extremely difficult to eliminate when heavy oils are involved. Because of its speed and convenience, the unsteady-state technique is favoured by most laboratories. In light oil systems there appears to be good agreement between relative permeabilities measured by the steady-state method and those obtained by the unsteady-stare technique. However, the equivalence of steady-state and unsteady-state measurements has not been confirmed in viscous oil systems. Steady-state measurements of relative permeability are generally free from viscous fingering effects. Therefore relatively high flow rates can be used to eliminate capillary end effects. The unsteady-states technique, in viscous oil systems, is likely to suffer from capillary end effects at low rates and from viscous fingering at high flow rates. The objective of this work was to compare steady-state and unsteady-state relative permeabilities in a viscous oil-water-Ohawa sand system. Both types of measurements were obtained at two temperatures (room temperature and 100 °C). Displacement were carried out at several different flood velocities to determine the effect of flow rate. The results show that in this system the two techniques provide different results. Moreover, the unsteady-state relative permeability was found to vary with flood velocity. The results appear to show that the unsteady-state technique may not be reliable when very adverse viscosity ratios are involved. Introduction Production of oil and gas from petroleum reservoirs usually involves flow of two or more immiscible fluids through a porous rock. Multi-phase now in porous media is it complex process that depends on a number of factors, including the absolute permeability; pressure drop; capillary pressure; fluid viscosities; and relative permeability of each phase. Of these the relative permeability is probably the most important parameter in determining the reservoir performance. Relative permeability, by definition, is a measure or the ability of a porous medium to conduct a given fluid when one or more other immiscible fluids are present. The resistance lo now or a given phase in a multi-phase situation depends primarily on how this phase distributes itself within the porous medium in the presence of other fluids.

Gasflooding Experiments for the East Side of the Yates Field Unit

Summary In a series of immiscible gasflood experiments at current conditions for the east side of the Yates Field Unit (450 psi, 82°F [3.10 MPa, 301 K]), the oil recovery efficiency of CO2 was compared with that of gas-cap gas (GCG). Flooding rates in vertically mounted, preserved-state cores were near the critical velocities for gravity-stable displacement. Oil recoveries with CO2 were 6 to 11 % of original oil in place (OOIP) greater than those of GCG. Flooding results were interpreted with a modified Buckley-Leverett end-effect simulator. With this simulator, the gas/oil saturation profile that results from capillary end effects could be modeled. The modeling study showed that incremental oil recovery with CO2 resulted from oil swelling, oil-viscosity reduction, and gas/oil interfacial-tension (IFT) reduction.

Relative Permeability From Unsteady-State Displacements With Capillary Pressure Included

Summary A semianalytic method for calculation of relative permeabilities from unsteady-state displacement data is developed. The method is based on the simultaneous solution of the fractional-flow equation and an integro-differential equation, derived from the material-balance and Darcy equations for immiscible displacement of two incompressible phases, including the capillary pressure by use of various volumetric relationships. This method for calculating two-phase relative permeabilities from unsteady-state displacement data is not restricted to the high-flow-rate experimental conditions used to overcome capillary end effects. Removal of this restriction allows the analysis of low-permeability cores with water and oil where the flow rates are low and capillary end effects are important. Our method allows direct calculation from the experimental data without intermediate interpretations of graphs.

Relative Permeabilities at Simulated Reservoir Conditions

Summary Relative permeability was determined at conditions from ambient to those simulating a depth of 1200 m [3,940 ft] from laboratory displacement data. The data were analyzed with the semianalytical interpretation method of Civan and Donaldson, which includes capillary pressure. The unsteady-state displacement method requires that the data be collected at high flow rates to diminish the influence of capillary end effects. including capillary pressure removes this constraint but results in a more complex mathematical model. The results show the capillary end effects and the error introduced by not including them in the calculation of relative permeability. When capillary pressure was ignored in our model, it reproduced the literature values. Relative permeability measurements at elevated temperature show the characteristic temperature effect of higher oil relative permeability and lower residual oil saturation (ROS). These effects result from a change of wettability to a more water-wet condition at the higher temperatures. The equipment used for relative permeability measurement can easily be constructed; in fact, some commercial designs can be used without modification. The results represent data at reservoir conditions; the data are taken on cores that are recompressed, eliminating the adverse influence of microfractures and changes of pore-size distribution frequently present in field cores run at ambient conditions. The displacement data are not restricted to high-flow-rate experimental conditions; removal of this restriction allows the analysis of low-permeability cores when flow rates are necessarily low.

Relative-Permeability Measurements: An Overview

Significant advances have been made in methods for accurate measurements of saturations and fluid distributions. Further research is needed to reduce (or properly account for) capillary end effects, to control hysteresis, and to minimize wettability changes involved in flow experiments. Studies are needed on modeling complex displacements in reservoirs with flow tests performed at idealized laboratory conditions. Similarly, improvements in interpretation of laboratory data and in scaling up for field use are still required. Until additional advances in technology are made, the best course of action is to generate both steady- and unsteady-state laboratory data, under simulated reservoir conditions, on carefully selected and preserved cores.

Determination of Three-Phase Relative Permeabilities under Reservoir Conditions by Hot Water and Steamflood Experiments

In order to help the physical and numerical interpretation of Emeraude's steam pilot, two-phase waterfloods at four temperatures (between 30 and 240°C) and a steamflood were performed in the laboratory using the same porous medium (compacted silt) and under reservoir conditions. Dynamic isothermal displacements were interpreted with a thermal simulator taking into account capillary end effects. The corresponding oil-water relative permeability curves were obtained by matching observed pressure drop and oil production. Results show that temperature influences the end-point saturations but not the shape of the curves. The steamflood experiment was carried out in an adiabatic core holder. Oil stripping and production of a large amount of CO2 caused by dissolution of carbonates were pointed out. The numerical interpretation of this experiment, by making use of the oil-water relative permeabilities, provided the three-phase oil relative permeability which is an essential datum for numerical interpretation of a steam drive pilot. Then a parameter study was used to quantify the influence of the different mechanisms involved in hot water and steam floods.

Hot-Water and Steamflood Laboratory Experiments Under Reservoir Conditions

Summary Hot waterfloods at four temperatures (between 30 and 240°C [86 and 464°F]) and a steamflood were performed on the same porous medium (compacted silt) under reservoir conditions. Dynamic isothermal displacements were interpreted with a thermal simulator, taking into account capillary end effects. The corresponding oil/water relative permeability curves were obtained by matching observed pressure drop and oil production. Results show that temperature influences the endpoint saturations but not the shape of the curves. The steamflood experiment was carried out with an adiabatic core holder. The oil recovery was 70% higher than the recovery by the hot waterflood at the same temperature (240°C [464°F]). Oil stripping and production of a large amount of CO2 caused by dissolution of carbonates were pointed out. In the numerical interpretation of this experiment, we used oil/water relative permeabilities to provide the three-phase oil relative permeability. These experiments allow a better understanding of steam displacement mechanisms and supply essential data for numerical interpretation of a steamflood pilot.

Effect of Temperature on Oil/Water Relative Permeabilities of Unconsolidated and Consolidated Sands

Abstract Over the past 20 years, a number of studies have reported temperature effects on two-phase relative permeabilities in porous media. Some of the reported results, however, have been contradictory. Also, observed effects have not been explained in terms of fundamental properties known to govern two-phase flow. The purpose of this study was to attempt to isolate the fundamental properties affecting two-phase relative permeabilities at elevated temperatures. Laboratory dynamic-displacement relative permeability measurements were made on unconsolidated and consolidated sand cores with water and a refined white mineral oil. Experiments were run on 2-in. [5.1-cm] -diameter, 20-in. [52.-cm] -long cores from room temperature to 300°F [149°C]. Unlike previous researchers, we observed essentially no changes with temperature in either residual saturations or relative permeability relationships. We concluded that previous results may have been affected by viscous instabilities, capillary end effects, and/or difficulties in maintaining material balances.

Caustic Slug Injection in the Singleton Field

The watered-out portion of this field in Nebraska appeared to be a good candidate for injection with NaOH. The results of the pilot program have been disappointing, however, probably because of poor sweep efficiency and because of deterioration of the caustic slug. Introduction Waterflooding is still the most widely used of all secondary oil recovery processes. Unfortunately, oil recovery by waterflooding is far from complete because of two inherent limitations: no matter how much water may be passed through a reservoir, some quantity of residual oil remains in the pores that have been swept by the injected water; and economic considerations require that waterflooding be terminated when the produced WOR exceeds some critical limit, even through portions of the reservoir may not yet have been swept. Mungan showed that, at breakthrough, oil recovery from oil-wet cores is always less than from water-wet cores and that, after breakthrough, large quantities of oil are produced, accompanied by a high WOR. Leach et al. and Mungan showed that in some cases the oil recovery can be made more efficient by changing the pH of the injected water. We shall discuss here a laboratory study of oil recovery efficiency in synthetic cores using Singleton crude and water of pH ranging from 3.5 to 12.5, and the field trial based on the laboratory findings. Laboratory Study Most of the displacement studies were performed in flow tubes packed with unconsolidated Ottawa sand. Each tube had a cylindrical section 2.062 in. ID and 30 in. long, and was made of monel metal. The inlet flange had a straight face, two entry ports, and the usual fluid distribution grooves. The outlet flange, however, was bored in the shape of a funnel, which was packed with silica flour consisting of a mixture of 325- and 400-mesh powder. This effectively eliminated capillary end effects. The tubes were packed with a sand having a broad particle-size distribution. Experience has shown that if the sand is well sorted in particle size, the resulting unconsolidated pack gives waterflood residual oil saturations that are unreasonably low, ranging from 10 to 15 percent pore volume (PV). A commercially available sand mixture, American Graded Sand Co. AGSCO No. 16 sand, was used to pack the tubes and gave waterflood residuals of about 30 percent PV. The particle-size distribution of this sand is given in Table 1. Much care was devoted to cleaning the sand, and a technique involving no vibration was developed to eliminate segregation of grains of different sizes during packing. Random cores from several packs indicated the porosity and permeability to be uniform. Displacement experiments permeability to be uniform. Displacement experiments were also performed in two 10-ft-long, 4-in.-diameter Berea cores. Formation sensitivity studies were made with small cores from the Singleton field. These cores had been handled and stored in a conventional manner, with no precautions taken to keep them fresh or in their native equilibrium state. The refined oil used - Klearol* - was purified using procedures described elsewhere. JPT P. 1569

BARUS EFFECT OF MOLTEN BLEND OF IONOMER AND ETHYLENE-VINYL ACETATE COPOLYMER

In order to clarify the rheological properties of polymer blends which is utilized for the modification of polymer, the viscoelastic behaviors in capillary flow of the molten blends of ionomer and ethylene-vinyl acetate copolymer, either of which contain common ethylene monomer unit and another monomer unit with opposite polarities, respectively, were investigated and the following results were obtained;(1) The plots of Barus effects against the blended ratio showed two symmetrical maxima and the blended ratios at maxima did not change even if the comonomer contents and the melt indices of components changed. The Barus effects at maxima decreased with shear rate at constant L/D.(2) The plots of the apparent shear viscosities against the blended composition suggested the tendency of the heterogeneous mixture, and the flow indices in power law changed slightly.(3) The capillary end effects of blends showed larger values than the values of the components, and had positive correlations with the Barus effects.(4) The mixed state could change complicatedly between homogeneous-, partially homogeneous-and heterogeneous-state, with the blended compositions which have influences on the intensities of the interactions between the different comonomers through the common ethylene units.

Progress Report on Spraberry Waterflood Reservoir Performance, Well Stimulation and Water Treating and Handling

Abstract Comparison of long term decline in oil production during cyclic waterflooding or pressure pulsing of part of the Driver Unit with steady injection-imbibition flooding in the Tex Harvey area led to large expansion of flood in the Driver Unit on the steady injection basis. While the flood has been successful, the major problem has been attainment of satisfactory oil production rates in most of the wells. Large volume fracture treatments of low capacity wells were unsuccessful in achieving sustained increases in production. A two-section area in the Driver Unit has already recovered 620 bbl of oil per acre by waterflood but other areas have not performed so well. San Andres water containing 300 to 500 ppm H2S is sweetened to 0.5 to 1 ppm H2S by extraction with oxygen-free flue gas. This prevents contamination of gas produced in the area and apparently it has reduced corrosion in minimum investment, thin-wall. cement-lined water distribution systems. Cement-lined tubing in injection wells has mitigated corrosion as effectively as thick polyvinyl chloride films have, and at less cost. Introduction As reported in the literature, the Spraberry field of West Texas has presented unusual problems for both primary production and waterflooding. Earlier information from the Spraberry Driver Unit included conception and evaluation of cyclic waterflooding or pressure pulsing in a nine-section pilot test as an aid to extraction of oil from the tight matrix rock and as a boost to normal capillary imbibition forces. An additional 5 years operation in that area, and performance of expanded steady injection water-flood, now covering a total of 68 sq miles, are reported herein. In addition, since the Driver Unit is one of the largest waterfloods in areal extent in the U. S., many operating experiences are presented for the benefit of engineers concerned with operation of other Spraberry floods or with other waterfloods where this reservoir technology and/or water handling technology may be adaptable in part. These include:attempts to improve producing well capacity through large volume fracture treatments,long-term performance of water treating plants utilizing oxygen-free flue gas to extract H2S from sour San Andres water,performance of thin-wall cement-lined pipe in water distribution systems including comparison between those sections carrying raw San Andres water and those carrying treated water, andcomparison of performance of various lining materials and subsurface equipment in water supply and water injection wells. These experiences are reported without regard to whether results are good, bad or indifferent. Since the operations reported are limited to the techniques, materials, and equipment actually used in the Driver Unit, no comparison is possible with results of other approaches used in other Spraberry floods or in waterfloods generally under different conditions. However, an attempt is made to quantify these experiences as much as possible in the space available to permit other engineers to select those parts applicable to their problems. Background The Spraberry, discovered in Feb., 1949, is a 1,000-ft section of sandstones, shales and limestones with two main oil productive members-a 10- to 15-ft sand near the top and a 10- to 15-ft sand near the base, having permeabilities of 1 md or less and porosities of 8 to 15 percent. Extensive interconnected vertical fractures permitted recovery of oil on 160-acre spacing from this fractional-millidarcy sandstone, but they made capillary end effects dominant. Primary recovery by solution gas drive is less than 10 percent of oil in place, with most wells declining to oil production of a few barrels per day when reservoir pressures are still in the range of 400 to 1,000 psi. Partial closing of the fractures with declining reservoir pressure is believed to be the cause of such low production rates at these relatively high reservoir pressures. In 1952 Brownscombe and Dyes proposed that displacement of oil by capillary imbibition of water from the fractures into the matrix rock might significantly increase oil recovery from the Spraberry, overcoming otherwise serious channelling of water through the fractures. A pilot test conducted by the Atlantic Refining Co. during 1952 through 1955 indicated technical feasibility of the process; but low oil production rates averaging 15 to 20 bbl/well/D failed to create significant interest in large-scale waterflooding at that time. JPT P. 1039ˆ

The Relation between the End Effect and the Normal Stress in Viscoelastic Fluid Flow

We have carried out a series of experiments to find out the capillary end effect in viscoelastic fluid flow. The main results of this investigation are : (1) The capillary end effect can be explained even by normal stress effect. (2) End correction factor does not always increase with increasing of the shear rate. (3) Linearity of the applied pressure-(l/d) plots indicates that the relaxation phenomena would not appear in this experiments.

Cyclic Water Flooding the Spraberry Utilizes "End Effects" to Increase Oil Production Rate

Abstract First response to large-scale water flooding in the fractured very low permeability Spraberry sand has led to a new unique cyclic operation. Capacity water injection is used to restore reservoir pressure. This is followed by many months production without water injection and the cycle repeated. Expansion of the oil, rock and water during pressure decline expels part of the fluids but capillary forces hold much of the injected water in the rock. At least with reservoir pressure restored and with partial water flood development, field performance has proved this cyclic operation is capable of producing oil from the matrix rock at least 50 per cent faster and with lower water percentage than is imbibition of water at stable reservoir pressure. Introduction The Spraberry Field of West Texas presents unusual problems for both primary production and water flooding. Extensive interconnected vertical fractures in the fractional-md sandstone permitted recovery of oil on 160-acre well spacing, but they made capillary end effects dominant. Primary recovery by solution gas drive is less than 10 per cent of oil in place. The concept of displacement of oil from the sand matrix by capillary imbibition of water has led to field techniques which promise greatly increased oil recovery. Free exchange of laboratory research, reservoir information and results of field pilot tests among the various companies has been very important in development of this technology. Five units covering a total of 170,000 acres have been formed for water flooding, and 10 other areas covering an additional 175,500 acres are in various stages of unitization. Part of the Driver Unit reaching fillup first has demonstrated very unusual waterflood behavior and indicated numerous operating problems that will develop within and among the various units. SPRABERRY ROCK AND PRIMARY PERFORMANCE The Spraberry, discovered in February, 1949, is a 1,000-ft section of sandstones, shales and limestones with two main oil productive members: a 10–15 ft sand near the top and a 10–15 ft sand near the base. In part of the field some thinner intermediate sands are oil productive, and others are water bearing. All sands have permeabilities of 1 md or less and porosities of 8–15 per cent. Ordinary core analysis and electric and radiation logs are ineffective in differentiating between oil productive and non- productive sands. Sands capable of containing producible oil are best identified by mercury injection capillary pressure measurement and, in some cases, by core water saturation. About 3,500 wells have been drilled in the 500,000-acre trend.Vertical fractures were observed in practically all Spraberry cores. Continuity and interconnection of fractures were confirmed by pressure interference among wells during early development.' Major fractures trend northeast-southwest as indicated by oriented cores and confirmed by five fluid injection tests, by analysis of the pressure transients observed during development, and by three interference tests in the Driver Unit Water Flood reported herein. Fracture spacing probably averages inches to a few feet.Spraberry wells typically produced 100–400 BOPD initially after hydraulic fracture treatments. By 1962 oil production had declined to an average of 12 bbl/well/day, near the economic limits of operation. Reservoir pressure had declined from 2,300 psi initially in the Upper Spraberry and 2,500 psi in the Lower Spraberry to 500–1,000 psi. Partial closing of the fractures with declining reservoir pressure is believed to be the cause of such low oil production rates at these relatively high reservoir pressures. Cumulative recovery of 208 million bbl of oil is 80 to 90 per cent of that recoverable by primary means. Performance of the entire reservoir is summarized in Fig. 1. IMBIBITION WATER FLOODING By 1952 reservoir performance indicated low primary recoveries. Most engineers, expecting serious channeling of injected fluids through the fractures, held little hope for secondary recovery. With its extensive background of research on the fundamentals of fluid flow within reservoir rocks, Atlantic's Research and Development Division on short notice in 1952 conceived that displacement of oil by capillary imbibition of water into the rock might significantly increase Spraberry recovery. Laboratory data reported by Brownscombe and Dyes scaled to probable reservoir conditions showed potential waterflood recovery equal to or greater than primary recovery with a 10–15 year flood life.A pilot test using three 40-acre injection wells, one central producing well and 18 surrounding observation wells demonstrated technical feasibility of the process. JPT P. 877^

Measurement of the flow of molten polymers through short capillaries

A method of treating experimental flow measurements on high polymers to obtain the basic shear diagram is described. Shear stress data are corrected to eliminate capillary end effects, and shear rate data are modified for the non-Newtonian behavior of the materials. Differences in flow behavior of commercial low-density polyethylenes are illustrated, and the effects of the two corrections are demonstrated. The method is applicable to other polymer melts. Although the data could be expressed by the power law, the fact that logarithmic plots of shear stress versus shear rate are not linear suggests that such relationships would be approximate. The data are expressed better by the threeconstant Powell-Eyring equation, although the significance of the three parameters is uncertain. The need to obtain the rheological constants from the basic shear diagram rather than from an uncorrected or partially corrected capillary flow diagram is emphasized. In support of previous investigators, irregularities in the extrudate were observed at high shear stresses. However, it was not possible to determine at what pressure the roughness was initiated. The shear diagrams calculated from the experimental data do not exhibit any point of inflection as reported in some studies.

Evaluation of high shear viscosity data from jet and concentric cylinder viscometers

This work compares and evaluates viscosity data obtained on similar fluids by two widely accepted high shear techniques. Both the jet and concentric cylinder viscometers are useful high shear methods. The major limitation of the jet viscometer is an inability to distinguish quantitatively between energy losses in laminar flow and those due to capillary geometry and experimental conditions. For example, the jet viscometer gives minima in viscosity-shear rate correlations which are difficult to treat. These minima are not found in concentric cylinder viscometer data for the same and similar fluids. The apparent viscosity increase at high shear in the jet may be due to factors other thanReynold's turbulence, as previously supposed. This effect may be due to molecular relaxation phenomena in certain cases. The jet viscometer might thus be used to evaluate molecular relaxation and/or other phenomena contributing to this effect. For a variety of systems, the concentric cylinder viscometer gives significantly smaller temporary viscosity losses due to shear than do the jet viscometer data. These comparisons are made using the maximum jet shear rate at the capillary wall. The differences are, of course, larger if average shear rates are used to compare the data. It is concluded that the jet viscometer results tend to be erroneous. This is possibly due to capillary end effects or problems with kinetic energy corrections.

Determining Gravity Drainage Characteristics on the Centrifuge

Published in Petroleum Transactions, Volume 207, 1956, pages 88–91. Abstract A method is given for predicting the complete gravity drainage characteristics of arbitrarily long columns from centrifuge drainage measurements on reconstituted core samples. Oil residuals corresponding to hundreds of years of normal gravity depletion can be obtained in a few hours on the centrifuge. The gravity flow rate at any stage of the depletion process may be determined from the time correlation derived, arid experimentally checked, in this study. Introduction Apart from the original observations of Muskat et al, research publications on the subject of gravity drainage have been largely concerned with establishing in detail the saturation, S as a function of the height, z, in a draining column at any given time, t. Some form of numerical integration must be employed to obtain production rates and cumulative production even when S(z, t) is known. Furthermore, the relevant experimental work has been concentrated on drainage of a single wetting liquid from unconsolidated media. Since oil production usually concerns the drainage of a partially wetting liquid from consolidated media, in the presence of connate water, and since it is unlikely that sufficient information exists to establish S(z, t) in detail for any natural reservoir, the published research work appears to be, at best, only qualitatively applicable to production problems. With this in mind, the present study was undertaken by the writer. Experiments were planned whose results would have two advantages over existing measurements:Observations were to be made on specific reservoir rock, reconstituted with formation water and formation oil. This would reduce their generality, from the research viewpoint, but increase their utility for production purposes.The measurements were to be self-integrating, i.e., the phenomena were to be described and interpreted in terms of cumulative results. Theoretical Development It was commonly known that centrifuging a liquid bearing porous medium increases the drainage rates and minimizes capillary end effects. The specific problem lay in selecting an acceleration, a, such that the mean residual saturation of a model cylinder was equal to the residual saturation of an arbitrarily long prototype column when the latter was drained by earth gravity alone.

Performance of Fractured Oil Reservoirs

Fractured reservoir rocks may be considered as made up of at least two porosity-permeability systems: one which accounts for the largest void space fraction of the reservoir and which makes up the pore space between the grains (intergranular porosity); the other which accounts for the smallest void space fraction and which makes up the pore space of the fractures and fissures. The former generally exhibits a low permeability, whereas the latter provides channels of high permeability which are the main reservoir fluid carriers to the wells, provided sufficient lateral continuity exists. In most cases, vertical continuity of the highly permeable system is also present and gravity segregation of the reservoir fluids may exist to a large degree. Under certain conditions of re ervoir rock wettability, the fluids will segregate into two zones of saturation, a lower zone of high oil saturation and an upper zone of high gas saturation. This results in a rapidly increasing gas-oil ratio in the early stage of depletion and in a low ultimate oil recovery. An alternative explanation of the behavior of fractured reservoir is also proposed whereby the low recovery by depletion drive is explained by capillary end effect which contributes to retaining a large fraction of the oil inside the blocks between fractures while permitting the evolution of solution gas. This end-effect capillary retention hypothesis would be particularly effective while low pressure gradients prevail within the reservoir. The hypothesis submitted herein for the explanation of the low oil recoveries from fractured reservoirs are intended to stimulate thinking so that experiments may perhaps be designed for their verification and for finding some solution to increasing recovery from such fields. Various approaches to this problem are suggested, but they have not received as yet the sanction of field use.