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By J. J. Taber

The turbulent flow drag coefficients, or friction factors, have been experimentally determined for the cut-tings normally encountered in drilling operations. The gas law and average drag coefficients for characteristically flat particles (limestones and Shales) and for angular to sub-rounded particles (sandstones) were used to extend Newton's equation to a more useful form. The resulting equations are expressions for the slip velocity of a particle as a function of the particle size and shape, the bottom-hole injection Pressure, and the Bottom-hole temperature. The velocities necessary to lift actual rock cuttings as observed in the laboratory were compared with velocities predicted from the derived equations. Results indicate that there is no single correct circulating velocity and that the commonly used 3,000 ft/min linear velocity may he sufficient to lift only very mall particles. The advantage, in terms of horsepower requirements, of cycling high pressure air to obtain lower compression ratios was shown. INTRODUCTION A promising departure from standard rotary hydraulic drilling is air or gas drilling. In many instances the rate of penetration and bit life increases resulting from this method have been very substantial. Further the application of air drilling in areas of lost circulation or water sensitive pay zones has been highly successful. Purpose For the drilling contractor, the practical question remains, "How much air pressure and volume should I have?' lt is necessary to have a reasonable knowledge of the air velocities and pressures required in air drilling operations for the proper design and most advantageous use of surface equipment and for adequate removal of cuttings from the borehole. Eased on experience, most operators agree that at least 3,000 ft/min linear velocity is necessary for satisfactory hole cleaning.' It was the purpose of this investigation to evaluate the drag coefficients, or friction factors, for the cuttings normally encountered in drilling operations, i.e., sandstones, limestones and shales, and to utilize the values obtained to develop an expression for the minimum velocities and pressures (hence the volumes) necessary to lift these cuttings. THEORY Several investigators have done extensive work on the ability of drilling mud to lift bit cuttings. They conclude that the ability of a drilling mud to lift cuttings is dependent on the density difference between the rock being drilled and the drilling mud, the cutting size and shape, the mud flow constants, and the flow state (laminar, transitional or turbulent) of the mud. However, drilling muds are not true fluids but have a variation of viscosity with velocity in laminar flow and a constant apparent viscosity in turbulent flow. A survey of the literature revealed that no experimental work had been done to determine the velocities necessary to lift actual rock cuttings using a compressible fluid such as air or gas. In 1953, Nicolson6 stated that in air drilling fluid mechanics the particles could be assumed spherical in shape and that ; constant drag coefficient of 0.5 could be used due to the highly turbulent flow of the circulating air. By equating the turbulent resistance on the particle to the gravitational force on the particle, he obtained the expression, ^ = 2.67^y ,.......(1) where V, is slip velocity of spherical particle, ft/sec; D is particle diameter, in.; p, is particle density, 1b/ft8; and p, is fluid density, lb/ft3. However, as stated earlier, most operators seem to agree that adequate hole cleaning can be obtained by circulating a sufficient volume of air to give a linear velocity of 3,000 ft/rnin in the annular space. Basic Equation The velocity with which a solid particle freely falls through a fluid will increase until the accelerating force, gravity, is equal to the resisting forces, buoyancy due to the fluid displaced by the particle and friction due to the relative motion of the particle through the fluid. When the accelerating and resisting forces become equal,

By L. W. Holm

This study shows that in the presence of foam, gas and liquid flow separately through porous media representative of reservoir rock. These results were obtained by using tracer techniques to measure the flow of the gas and liquid comprising the foam. Foam does not flow through the porous medium as a body even when the liquid and gas are combined outside the system and injected as foam. Instead, the liquid and gas forming the foam separate as the foam films break and then re-form in the porous system. Liquid moves through the porous medium via the film network of the bubbles and gas moves progressively through the system by breaking and re-forming bubbles throughout the length of the flow path. The flow rates of the gas and liquid are a function of the number and strength of the films in the porous medium. There is no free flow of gas; i.e., no continuous gas phase. On the basis of these results, foam can be expected to improve a water flood or gas drive by decreasing the permeability of the reseruoir rock to a displacing liquid or gas. This improves the mobility ratio and thus the conformance of the flood. INTRODUCTION Foam is formed when gas and a solution of a surface active agent are injected into a porous medium either simultaneously or intermittently. During the past few years, several papers have been published on the subject of foam flow in Dorous media. Foam has been used successfully in the removal of capillary water blocks from producing formations.''2 The use of foam in gas storage reservoirs to reduce gas leaks and to increase storage capacity has been considered in recent years. Foam has also been investigated as an oil displacing agent,3-5 and as an agent to improve the mobility ratio in a waterflood.6-10 However, the mechanism by which the gas and liquid phases comprising the foam flow through a porous medium has nor been described adequately. Normally, when two immiscible phases (gas and liquid) flow concurrently through a porous medium, each phase follows separate paths or channels. At given saturations of the two phases, a certain number of channels are available to each phase, and as saturations change, the number and configuration of the channels available for each phase also change. The effective permeability of each phase is a function of the saturation of that phase only, and the flow of each phase can be described by Darcy's law. When foam is present, the effective permeability of the porous medium to each phase is greatly reduced compaced with permeabilities measured in the absence of foam.6,11-13 Based upon the observed flow of surfactant solutions and gas in capillaries, it has been concluded that the gas and liquid may flow separately or they may flow combined as foam. At least four mechanisms have been postulated to explain how fluids flow with foam present: 1. A large portion of the gas is trapped in the porous medium and a small fraction flows as free gas, following Darcy's law.9 2. The foam structure moves as a body; the rate of gas flow is the same as the rate of liquid flow. 6,13 3. Gas flows as a discontinuous phase by breaking and re-forming films. Liquid flows as a free phase.12 4. A portion of the liquid and gas move as a foam body while excess surfactant solution moves as a free phase.14 It also has been suggested that different flow mechanisms exist for high quality (dry) foams made from dilute surfactant solutions and for foams made from more concentrated solutions. Studies conducted on the flow of foam through capillaries have shown that a plug-type flow occurs and that foam flows as a body.6,15 Fried also has described the flow of foam through porous media as

Jan 1, 1969

By W. C. Hardy, B. W. McArthur

The purpose of this work is to show application of laboratory data in calculating solution gas-drive performance of the Cisco K-I reservoir. Included herein is a diagram showing the graphical relationship between six variables common to all solution gas-drive mechanisms. With an iterative process one may assume existence of any of these six variables at a particular pressure and calculate the production performance likely to occur in a reservoir produced by solution gas drive. Four unique pressure values are described at which the material balance equation alone is sufficient to predict the cumulative volumes of gas produced. Information derived from these pressure points establishes a criterion for determining compatibility of the pressure-volume-temperature (PVT) analysis of the produced crude with the gas production history. Two averaging procedures are used to arrive at a relative permeability-saturation relationship which describes the field-wide performance. INTRODUCTION The Cisco K-1 reservoir is a lenticular-type sand structure lying at approximately 6,300-ft subsurface. It is located in the H. and T. C. Railroad Co. Block 97, SW 1/4 S 392 and NW 1/4 S 385, Scurry County, Tex. Correlation of data from logs indicated that the Cisco K-1 reservoir occupied approximately 3,218 acre-ft of space with a closure of from 15 to 20 ft. Analysis of the production data indicates that the initial formation pressure and temperature were 2,450 psig and 121°F, respectively. The bubble point occurred at 1,715 psig after production of 12,256 STB oil and 11,520 Mcf gas. Only traces of water have been produced since initiation of production. Successive material balance calculations from June, 1952, to June, 1957, showed that no initial gas cap or water influx has contributed to production of oil and that the Cisco K-1 reservoir originally contained approximately 1.44 X 10" STB of oil. THEORY Methods for calculating solution gas-drive perform-

By J. W. Marx, R. H. Langenheim

The authors are to he complimented for a timely presentation of useful information concerning application of heat to oil reservoirs to increase the rate and ultimate recovery of oil. The solution for heated area resulting from constant rate injection of a hot fluid, presented by the authors, and the fluid-flow analogy, solved by Carter,' are particularly interesting in that 110 restriction is placed on the direction of development of the heated area. It is not necessary that the heated area grow radially. Thus the solution could provide useful information for heat injection in any type of well pattern with any specified swept area data. However, it was assumed in the development that the heated region would remain at a constant clevatcd temperature. Vertical heat losses were computed on this basis. Physically. the assumption that the heated region will remain at a constant temperature (independent of distance from the injection point) appears to require that the heat injection medium be stcam, or other condensible gases near the boding point at injection pressure. If a hot liquid below the boiling point or a hot gas considerably above saturation temperature were used, the temperature of the heated region would decrease with distance from the injection well. Lauwerier2 has discussed this problem for a linear system. (See also Jenkins and Aronolsky; and McNiel and Nelson.') Thus, the authors' solution applies more nearly to steam injection than to hot water injection or hot, non-condensable gas injection. Assuming steam as the injection medium, it appears that steam would pass through the constant-temperature heated region and condense upon contact with the unheated sand. The tempcrature in the condensing region would probably be governed by the release of heat of vaporization required for phase equilibrium at the existing pressure distribution. Temperatures in the region would also be influenced by vaporization of hydrocarbon. Thus, it is doubtful that an expression for radial temperature distribution based on heat conduction only (such as the authors' Eq. 9) would have practical significance. As pointed out by Marx and Langenheim, the growth of the heated area under constant rate steam drive will eventually be limited economically by vertical heat loss. The possibility of continuing to move heat economically by cold water injection or by increasing the steam injection rate appears to be a very important consideration. (Movement of liquids away from the injection well should increase injectivity.) Fortunately, the solution presented by the authors may be generalized to thc case of a variable heat injection rate. The general solution is:

By J. Weijdema, D. N. Dietz

In the conventional underground combustion process (dry combustion) much heat is left behind in the swept formation and goes to rva.rte. Econonmy can be improved by heat recuperation through water injection. This is most advantageous if done at the earliest opportunity before much heat is dissiputed to cap and base rock. Water injected simultaneously with the air will flash to superheated steam, which passes through the combustion front together with the nitrogen from the air. A condensation front traveling up to three times as fast as the combustion front drives out the oil. In this type of wet combustion, the water evaporates before it reaches the combustion zone. The evaporation front travels more slowly than the combustion zone. If so much water is injected that the evaporation front overrun the combustion front, combustion in that spot will be quenched and some unburned fuel will be left behind. Air reacts with the oil farther down-stream where steam temperatures occur; at steam temperature, the air reacts rapidly with the oil. Velocity of the combustion front is increased thereby and is governed essentially by the water-injection rate. In the extreme case of high water-injection rate, a short heat wave of constant length is driven through the formation by water injection. Once this wave has been established, no more heat need be generated than that required to make up the heat losses from the short heat wave; a relatively low rate of air injection will suffice. The feasibility of partially quenched combustion has been confirmed in tube experiments. A heat wave at steam temperature is observed. Chemical analyses of flue gas indicate preferential burning of hydrogen while a carbonaceous residue is left in the formation. Introduction A disadvantage of so-called dry in situ combustion is that air-compression costs are rather high. An air consumption of about 400 std cu m/cu m (400 scf/cu ft) of formation swept is an accepted figure. This high consumption is mostly wasted since much heat is left behind in the depleted oil sand. Methods were investigated for recuperating as much as possible of the heat left behind. This paper deals only with basic principles and is confined mainly to one-dimen- sional flow without lateral heat losses; experiments were conducted in relatively narrow, well insulated tubes. If some water is injected with the air, it will turn to superheated steam in an evaporation front, which should travel behind the combustion front. The steam having passed the combustion front causes a steam drive by a condensation front that can travel faster than the combustion front. The latter needs to travel only part of the distance covered by the oil-displacing condensation front, and thus consumes less air. The water-air ratio would seem limited to that at which cold water overruns the combustion. This limitation was deliberately exceeded considerably in theory and experiments. It was found that combustion is then indeed quenched, but only locally. Farther downstream, the oxygen finds residual oil at steam temperature, which is suficiently high to ensure rapid oxidation. Thus, the combustion front uses only part of the available fuel because it is chased through the formation faster than its normal velocity. No heat is left behind. This new process is called "partially quenched combustion". At the upper limit of the water-air ratio, a small heat slug is moved through the formation by the flow of water and steam. Only a small flow of air is needed since it has only to generate sufficient heat to make up for the lateral heat losses of the short heat slug. Theory Although many factors complicate underground combustion, the processes will be presented in their simplest form. For this reason, one-dimensional flow without lateral heat losses is assumed. Heat conduction in the direction of flow also is disregarded. Under these conditions, dry combustion causes very high temperatures. The heat-carrying capacity of the gas stream is small. Heat generated by oxidation of a residual oil saturation is retained in the sand. The available fuel determines the air requirement and the temperature obtained. Accepting the often-mentioned air consumption of 400 std cu m/cu m (400 scf/cu ft) formation, we calculate a temperature of the swept sand of 1,200C (2,192F) (Fig, I). If water is injected at a modest rate with the air, it will flash to superheated steam upon contact with the heated sand. One cu m (35.31 cu ft) of hot formation will evaporate about 0.5 cu m (17.66 cu ft) of water, and thereafter will accommodate (at an estimated 0.80 saturation and an assumed 0.40 porosity) another 0.3 cu m (10.59 cu ft) of water in cold condition. As long as less than 0.5 + 0.3 = 0.8 cu m (28.25 cu ft) of water is injected for every 400 std cu m (14,125 scf) of air (water-

Jan 1, 1969

By J. L. Thompson

There are two basic forms of the LPG-slug process: the gas driven and the water driven. The pressure required for miscibility between gas and LPG prohibits the use of the gas-driven LPG process in shallow reservoirs. The water-driven LPG slug process normally exhibits good sweep efficiency. However, displacement of the LPG by water is poor. An improvement in this process appears possible by injecting a slug of carbon dioxide between the LPG slug and the water drive. Laboratory experiments were conducted in homogeneous linear systems to determine the effect of pressure on the various displacement zones. In the carbon dioxide-LPG displacement zone, the effect of pressure on the displacement efficiency is negligible above the miscibility pressure. However, the displacement efficiency decreases linearly with decreasing pressure below the miscibility pressure. With water displacing carbon dioxide, it was found that the recovery of carbon dioxide after water breakthrough can be predicted from its solubility in water. A displacement test was conducted with LPG and carbon dioxide slugs large enough to avoid interference between the oil-LPG, LPG - carbon dioxide and carbon dioxide - water displacement zones. Under these conditions, essentially complete oil and LPG recovery was obtained. However, a substantial amount of carbon dioxide was left in the core at water breakthrough. INTRODUCTION It has been shown in homogeneous linear systems that essentially complete oil recovery can be obtained by displacement with a miscible fluid such as LPG. Economic considerations dictate that the valuable LPG also be recovered. Methods proposed for recovering the LPG include (1) displacement with natural gas at a pressure high enough to make the two fluids miscible1 (the disadvantage of this method is that the required pressure of about 1,500 psi is too high for shallow reservoirs) and (2) displacement of the LPG with water2 (principal disadvantage is that a large amount of LPG remains in the formation because of poor displacement efficiency). This paper treats an improvement in the water-driven LPG slug process3,4 where carbon dioxide is injected between the LPG and water. Carbon dioxide is completely or at least partially miscible with propane and soluble in water; thus, displacement efficiency is improved at both ends of the carbon dioxide slug. To minimize effects of other variables, all experiments were conducted in linear core systems. GENERAL PROCESS DESCRIPTION The displacements of propane by carbon dioxide and carbon dioxide by water are considered separately, assuming enough of each is injected to prevent mutual interference. Displacement descriptions are confined only to the part of the pore volume containing mobile fluids unless otherwise specified. The schematic representation is given in Fig. 1. Starting at the producing well, a zone containing only oil is followed by a zone containing a single-phase mixture of propane and oil. The concentration of propane increases in the direction of the injection well and ultimately grades to pure propane. Then follows a zone containing a mixture of propane and carbon dioxide in continuously varying proportions until 100 percent carbon dioxide is reached. In this zone, the concentration of carbon dioxide in the immobile water phase also varies from zero to full saturation. Whether the displacement of propane by carbon dioxide is of complete or partial miscibility depends on pressure and temperature (Fig. 2). If the horizontal line representing the prevailing pressure intercepts the boundary curves of the phase envelopes for the prevailing temperature (i.e., if the pressure is lower than the critical

By W. B. Hickman, J. J. Pickell, B. F. Swanson

Many physical properties of the porous media-immiscible liquid system are dependent upon the distribution of fluids within the pores; this in turn, is primarily a function of pore structure, liquid-liquiri interfacial tcnsion and liquid-solid wetting conditions. The cnpillary pressure hysteresis process provides a means of investigating the influence of pore structure upon fluid distribution for consistent sur/acc conditions. Invcstigntiot2s indicate that residual non-wetting-phase saturations /ollozuir,g the imbibition process (i.e.,wetting phase displacing nor2-wctting phase) are dependent upon both pore structure and initial non-raetting phase saturation and suggest that residual fluid is distributed as Discontinuous ,globules, one to a few pore sizes in dimension, thrnugh the entire range 01 pore sizes originally occupied. It clppears that air-mercury capillary pressure dala adequntely rellect the distribution of fluiris in a water-oil system when strong wetting condition preliczil. An oil-air counter-current imbibition technique has also been found to provide a rapid rneans of obtaining residual-initial saturation data. In a majority of cnses, rcsidual saturations detf-rniinecl from the oil-air or air-mercury process reasonably approximate residual oil saturation following water drive of a strongly water-wet medium. INTRODUCTION A reliable estimate of recoverable reserves depends not only on the amount of original oil-in-place but also on pore geometry and distribution of fluids within the pores. A critical parameter determining the recovery from a reservoir under waterflood, for example, is the amount and distribution of residual oil within the various rock types present. The purpose of this paper is to investigate the mechanism of capillary trapping and assess its importance in laboratory measureqents of residual oil saturation. The degree of wettability of a reservoir rock is recognized as an important factor in waterflood or imbibition experiments. In this paper, however, only the water-wet case has been considered. Considerable experimental evidence1 suggests that for water-wet rocks, capillary forces predominate in tile distribution of fluids and that viscous forces in the range normallv of interest in the reservoir have a minimum influence on residual oil saturation. It follows that if the ultimate recovery is controlled by pore geometry, a unique residual non-wetting phase saturation should exist for a given set of initial conditions. Two laboratory procedures.found to be extremely useful in the study of pore structure and degree of fluid interconnection at various saturations are decribed. Although air-nercury capillary injection curves have been used2 previously to characterize the drainage case, the withdrawal or imbibition case can provide valuable supplementary data. The air-mercury process, however, has several disadvantages; it is difficult to run in a sufficiently accurate manner, mercury does not always act as a strongly non-wetting liquid and in the air-mercury process the sample is rendered unsuitable for future analyses. An alternative process is described in which air is the non-wetting phase and naptha, hentane, octane or toluene is the wetting phase. INTERFACIAL TENSION AND CAPILLARY PRESSURE Interfacial tension between immiscible fluids is due to the difference in attraction of like molecules as compared with their attraction to molecules of the neighbouring fluid. This net attraction results in a tension at the interface. To extend the interface; thus, interfacial tension s can also be thought of as free surface energy. Interfacial tension is normally expressed as dynes/cm, and interfacial energy is measured in ergs/cm2 hence, both have dimensions ml A 2 and are numerically equal.

Jan 1, 1967

By K. Leutwyler

The key to realistic casing stress analysis in thermal recovery installations is accurate knowledge of the temperatures involved. Much information leading to prediction of heat losses from tubing string to wellbore has been published. This .same information permits calculation of casing temperature under certain conditions. This paper reviews the basis for most of the published work, the line source solution to the diflusivity equation and examines some of its application criteria in the light of unsteady-state conditions. An alternate finite differences method is presented for correlation, and experimental data pertaining to the heat transfer mechanism in the annulus is reported. In the light of the information presented in the paper, it appears that the assumption of a line source for the tubing-wellbore system is valid even for reasonably short periods of heat flow, .such as "steam soak" operations. The empirically modified equation presented earlier matches computer derived results of the finite differences approach lor periods as short as 50 hours. Previously predicted cas ing temperatures and the associated stress levels are thus verified based on these correlative computations and the reported experimental information. Fall out from the computer output resulting in some studies of the influence of insulating cement properties on casing temperature, and experimentally studied effects of nitrogen placed in the annulus at various pressures., are described. INTRODUCTION Generally speaking, predictions of average casing temperatures have been based on an idealized model involving a centralized tubing string at uniform constant temperature radiating energy towards the casing under steady-state conditions.'. ' Heat is transferred away from the casing to the formation by unsteady-state conduction across thermal barriers consisting of cement and the mud sheath. Heat balances written on the casing permit prediction of instantaneous casing temperatures. During early periods of injection, casing temperature varies appreciably as a function of time; however, for long injection times this variation decays as heat flow from the wellbore to the formation stabilizes, and it becomes virtually negligible as conditions surrounding the wellbore become quasi-steady-state (Fig. 1). Carslaw and Jaeger -escribe a solution to the diffusivity equation for a line source (Fig. 2). A constant supply of heat is introduced into the medium from the line placed into the origin of the x-y coordinate system and parallel to the z-axis. Heat spreads outward in the infinite cylindrical solid and the temperature increase on a line going through point (x, y) parallel to the z-axis at a distance r can be predicted by: The following criterion must be considered: the Carslaw and Jaeger equation is obtained on the basis of a large

Jan 1, 1967

By N. Mungan

Laboratory imbibition and displacement experiments were performed using crude oil and cores drilled with water and preserved under anaerobic conditions. The purpose of these tests was to determine reservoir rock wettability and to find out if more oil could be recovered by use of NaOH solution than by conventional waterflooding. The preserved cores were found to be oil-wet. Contrary to work in the literature, these cores changed to water-wet upon contact with air. After exposure to air for a week, the cores yielded more oil by waterflooding than when preserved under exclusion of air. At reservoir temperature of 160F, flooding the preserved cores with 0.5N NaOH solution recovered more oil than an ordinary wa-terflood, and additional oil when following a waterflood. When the caustic solution was used from the beginning, all the extra oil was obtained before breakthrough; when the caustic followed a conventional waterflood, the extra oil was produced in the form of an oil bank ahead of the injected caustic. The increase in oil recovery resulted from wettability reversal. Also, use of caustic reduced the volume of injection required to flood out the cores. At room temperature, however, the caustic solution did not reverse the wettability and gave no additional oil recovery. Cores which had become water-wet by air exposure or caustic flooding were restored to their original oil-wet state when saturated with crude oil and allowed to equcilibrate at reservoir temperature for two weeks. Therefore, in the absence of preserved cores, it may be possible to restore weathered cores to their original wettability for use in laboratory floods. INTRODUCTION Waterflooding has been in use since 1865, and is by far the simplest of secondary recovery methods. Unfortunately, most waterfloods are inefficient in recovering oil, often leaving half or more of the original oil in place un-recovered. The low oil recovery generally results from low sweep efficiency and low displacement efficiency. Consequently, to increase oil recovery by waterflooding, sweep and displacement efficiencies should be improved. Sweep efficiency is primarily affected by reservoir heterogeneities and mobility ratio, while displacement efficiency is affected by the capillary forces between fluids and rock surfaces. For petroleum reservoirs, the capillary forces are expressed in terms of interfacial tension and wettability. If oil recovery is to be improved significantly in water- flooding, the capillary forces holding the oil in the raervoir porous matrix must be reduced or eliminated. One way to reduce capillary forces is to inject commercial surfactants ahead of the injection water into the reservoir. Laboratory tests of this method have shown no promise of an economical process yet, and no increase in oil recovery was obtained in the field trials which have been reported. Work is continuing in many companies to find surface-active agents which, in workable concentrations, can yield substantial added oil recovery. Another way to change capillary forces operating in petroleum reservoirs is by changing the pH of the injected water. Wagner et al.' showed that change in the pH sometimes activates the surface-active materials natural to some crudes and brings about gross wettability change. Since pH alteration can be obtained with cheap chemicals, such as hydrochloric acid or sodium hydroxide, the process shows promise of being economical in a field application. Pan American Oil Corp. reported oil recovery by use of caustic solution from a flooded-out reservoir.' Their test, conducted at a small additional cost, yielded results which were so sufficiently favorable and encouraging that the wettability reversal flood was expanded to portions of the field not previously flooded.13 It is important to bear in mind that changes in the pH of the water not only can reverse wettability but also can lower the interfacial tension between water and crude oil. Reisberg and Doscher4 have studied the pH dependency of the interfacial tension of Venture crude using sodium hydroxide solutions of various concentrations. Their data show that the interfacial tension was lowered from 23.0 to 0.02 dynes/cm by increasing the NaOH concentration from 0.005 to 0.5 per cent by weight. Thus, the use of NaOH may lead to additional oil recovery due to both wettability reversal and lowering of interfacial tension. Whether alteration of pH results in wettability reversal from oil-wet to water-wet and increases oil recovery depends on wetting properties of the reservoir rock and the crude. This necessitates delicate laboratory experiments, with suitable core and fluid samples from a field. Although many investigators have studied wettability reversal floods in the laboratory,1,2,5,6 these studies have been carried out with synthetic porous media, refined laboratory fluids and surface-active chemicals to simulate the process. The study presented in this paper is the first time that wettability reversal by pH alteration has been accomolished in laboratory core floods using carefully preserved natural cores, live crude and with experiments performed at reservoir pressure and temperature.

Jan 1, 1967

By H. R. Froning, R. O. Leach

In wertability alteration flooding, a chemical agent is rnoved through a reservoir by the flood water to increase oil recovery by decreasing the degree of wetting of the rock by the oil. Substantial amounts of the chemical may be lost during movement through the reservoir. The extent of the loss, and therefore the economics of the process, depends in some cases on factors which are difficult to reproduce in the laboratory. Therefore, a short-duration, low-cost field test method is needed to permit evaluation of chemical requirements under actual field conditions. This paper describes a small scale rest conducted at a single well for measuring chemical requirements, thereby giving a more reliable evaluation of this important factor in the applicability and economics of the process. In the rest a small wafer slug containing the chemical agent and a nonadsorbed tracer is displaced into the reservoir by a known volume of wafer. The well is then placed on producrion. Chemical loss per barrel of pore volume contacted is calculated from [he fractional recoveries of the agent tested and the nonadsorbed tracer. The method has been used to determine within the actual reservoirs the chemical requirements for both a sandstone and a dolomite reservoir. Several chemical agents are potentially available for wettability alteration flooding, although none is universally applicable. For some applications of the method, chemical costs per barrel of additional oil recovered can be substantially less than one dollar. INTRODUCTION Wettability alteration flooding provides a means of increasing oil recovery from reservoirs by decreasing the degree of wetting of the rock by the oil and increasing the displacement efficiency of the flood water. Earlier studies demonstrated a relationship between oil recovery during waterflooding and the degree of wetting of a rock surface by an oil. The application of wettability alteration flooding to the Harrisburg field of Nebraska provided a field test' of this recovery process. Subsequently, additional laboratory and field tests have developed additional procedures for evaluating wettability alteration flooding, and have indicated where the process may be applicable. Applicability of this process to specific reservoirs is determined by a progression of tests to determine sus- ceptibility of the reservoir to alteration of its wettability, to indicate the degree of recovery improvement and to estimate the amount of chemical required to process the reservoir. The economics of applying improved oil recovery processes depends not only upon the degree of improvement in oil recovery achievable by the process but also upon the process costs and the timing of the income and the investment. Emphasis in this paper is on the expenditure aspects of the process. The work reported in this paper indicates that the chemical investments required for wettability alteration flooding are substantial. For evaluating the economics of a potential flooding application it is imperative that a sound estimate of the chemical requirements be made for the reservoir. Generally, true reservoir conditions are not adequately simulated in laboratory chemical propagation tests. Because of wide well spacings, many years might be required to obtain chemical propagation data from conventional pilots or inter-well tests. Consequently, n short-duration, low-cost method is needed to determine chemical requirements in the field. The potential applicability of wettability alteration flooding is discussed, as well as the economics of wettability alteration with respect to the inherent and imposed restrictions on the timing of income and investments. DETERMINATION OF CHEMICAL REQUIREMENTS In the process of moving a chemical bank through reservoir rock, some of the chemical agent lags too far behind the flood front to be effective or is otherwise lost to the reservoir system. The extent to which these losses occur overshadows the reductions in chemical concentration due to diffusion and to mixing with the reservoir fluids. Experience indicates that almost without exception, chemicals which induce a wetting change undergo either sorption reactions or chemical reactions with mineral constituents of the pore surfaces. Other reactions may occur between the added chemical and the reservoir oil and water. Even in limiting consideration to reactions of the relatively inexpensive inorganic salts, bases and acids, the reactions may be exceedingly complex. Reservoir pore surfaces consist of more than silica in sandstone reservoirs, and more than calcite or dolomite in carbonate reservoirs. Many mineral species are present, each exhibiting specific tendencies to react with an injected chemical. The reactions which occur can consume enough of the agent to have an important effect on economics. These reactions can cause a change in pH of the chemical bank, or may remove some of the active chemical by precipitation, adsorption or reaction to form a new chemical which may or may not be effective in

By W. W. Krech, T. E. Perkins

As fractures are propagated through rocks, energy is absorbed near the extending crack tip. Apparent surface energies for several rocks have been measured by cleavage under dynamic con-ditions. At nominal crack velocities from 0.5 to 500 in (min, measurements showed that fractures propagated in discrete jumps. Calculated surface energies and moduli were relatively insensitive to nominal rate of cleavage. in another set of experiments, rocks were cleaved under high confining stresses. The rocks were submerged in low leak-off fluids which formed a filter cake on the freshly cleaved surfaces (similar to the hydraulic lracturing process). Apparent surface energies were increased substantially as the surrounding fluid pressure was increased. Moduli in bending increased significantly upon application of the first 1,000 psi but were insensitive to stress level at greater pressures. INTRODUCTION For almost 20 years, hydraulic fracturing processes have been utilized effectively to stimulate oil and gas wells. During this period, some process improvements have resulted from studies of fracture orientation, mechanics of fracturing, areas generated, conductivities of cracks, etc. Yet many questions remain concerning the conditions and pressures needed during fracture propagation. In this paper we will report additional studies of the mechanics of fracture extension. It was shown previously3 that large rock samples could be cleaved under controlled conditions so as to measure the apparent surface energy (that amount of energy absorbed per unit area of new surface created). In this paper we consider the effects of two additional factors on surface energies, viz.: (1) effect of cleavage rate and (2) effect of confining stress level. THEORY Cleavage experiments were conducted on rock samples similar to that illustrated in Fig. 1. Blocks of rock several inches wide, 2- to 3-in. thick, and up to 3 ft in length were grooved longitudinally with shallow guide slots. A crack was initiated and allowed to extend along the web as the top of the rock specimen was pulled (or pushed) apart. Auxiliary equipment permits the measurement of (1) force applied at the top, (2) separation at the top and (3) crack length. (Further experimental details will be given in the next section.) The rock beams created by the crack are considered ton be cantilever beams. The deflection (or separation of the rock beams) at any point is calculated 4,5 by the beam Eq. 1.

Jan 1, 1967

By O. R. Wagner, R. O. Leach

Immiscible displacement tests were performed in a consolidated sandstone core over the interfacial tension range from less thdn 0.01 to 5 dynes/cm to better define how interfacial tension (IFTJ reduction can lead to increased oil recovery. Data obtained were displacement efficiency at breakthbrough vs IFT for both drainage and imbibition conditions. These tests simulate water flooding under oil-wet and water-wet conditions, respectively. Results of the study have shown that displacement efficiency under both oil-wet and water-wet conditions can be markedly improved by a sufficient reduction in IFT. In the particular porous media used and for the low pressure gradients employed, the IFT must be reduced to a value less than about 0.07 dynes/cm to achieve increased recovery at the time of breakthrough of the injected phase. Below 0.07 dynes /cm, further small reductions in IFT result in large increases in displacement efficiency. Observed increases in recovery were obtained at pressure gradients which are well below those which can exist in the interwell area of a reservoir under water flood. The effect of pressure gradient on recovery is discussed. INTRODUCTION A residual oil saturation remains in rock which has been water flooded because, under usual reservoir conditions, the driving force which can be generated is inadequate to expel oil trapped by capillary forces. Since these capillary forces can be reduced by reducing the IFT a frequently studied method of increasing oil recovery has been the use of surfactants to reduce the water-oil interfacial tension. Mungan l observed improved recovery in both water-wet and oil-wet systems at 1.1 dyne /cm IFT, finding that the amount of improvement was greater in oil-wet systems. Moore and Blum,2 working with visual flow cell micro-models, con- cluded that recovery cannot be improved in water-wet systems by injecting surfactant solutions. They calculated that, for a pressure gadient of 1 psi/ft in their model, the IFT must be reduced to 0.03 dynes/cm to release oil trapped under water-wet conditions. Berkeley et al.3 indicated that, at representative field flooding rates, the IFT must be reduced to 0.001 dyne/cm to improve recovery, Thus, there is a wide variation of opinion about the IFT levels needed to improve recovery under field conditions. These previous investigators all have used as their experimental method the addition of surfactants to the injected water. The use of surfactant solutions to reduce IFT creates two experimental problems: (1) the loss of surfactant through adsorption on reservoir rock can obscure the true IFT value which exists at the displacement front, and (2) at very low values of IFT emulsifica-tion of oil and water commonly occurs. It is difficult, therefore, to determine whether the increased recovery is caused by IFT reduction as such, or is instead caused by emulsification. Also the properties of the available surfactants limit the IFT range which can be studied. In the present study the purpose is to better define how interfacial tension reduction can lead to increased oil recovery. A matter of great interest is the amount of recovery improvement potentially achievable in this way. The study was made using very low pressure gradients which was well within the range achievable by water flooding in the interwell region of petroleum reservoirs. A unique experimental approach was chosen to avoid adsorption and emulsification problems, and to allow convenient control of IFT. The fluid phases used were the equilibrium vapor and liquid phases of the methane-n-pentane system. The interfacial tension level was varied by changing the equilibrium pressure of the methane-pentane system over the range from 1,200 psia to near the critical pressure (2,420 psia). All tests were performed at a controlled temperature of 100F. The IFT-vs-pressure relationship for the methane-pentane system was based on the data of Stegemeier and Hough,6 and on new data obtained in this study. With this experimental approach it has been possible to study displacement at lower values of IFT than have been previously investigated.

Jan 1, 1967

By D. E. Menzie, D. L. Dauben

This paper discusses the physical parameters involved in the slow flow of high molecular weight polymer solutions in porous media. The interacting effects of polymer properties and porous media properties on flow performance are considered. Experiments were conducted with the polyethylene oxides, with molecular weights ranging from 200,000 to over 5,000,000. Frontal advance velocities ranged from I to 30 ft/day. The porous matrix consisted of a flow cell packed with glass beads. Polymer solutions were characterized by viscosity and normal stress measurements. Under certain conditions, unexpectedly high flow resistance was observed. This behavior was observed to be a function of flow rate, pore size, polymer molecular weight and concentration. The polymer solutions exhibit "dilatant" flow behavior in porour media in contrast with the pseudo-plastic behavior in simple flow systems. A theoretical ex-planation of such behavior is presented. INTRODUCTION The use of polymers in the injected water of a waterflood increases oil displacement efficiency by reducing the mobility (k,/pu) of the driving phase. A reduced driving phase mobility results in improvements in the areal sweep efficiency and in the vertical coverage in stratified reservoirs. This mobility reduction may be achieved by a permeability reduction, a viscosity increase or by a combination of the two. Early attempts at increasing the injected water viscosity were not successful because of the poor economics involved. The use of such materials as glycerin, sugar or glycols to increase water viscosity was not economically feasible. Attempts in using certain naturally occurring polymers were not too successful because of the high polymer losses to the rock. A high molecular weight, partially hydrolyzed polyacry-lamide was introduced 3 years ago as a waterflood additive.',' Initial work by Pye' indicated that the presence of these polymers in dilute concentrations decreases the water mobility 5 to 20 times more than would be expected from measurements of the solution viscosity. Such an effect would be of obvious economic value since only a small polymer concentration would be required to accomplish a large reduction in water mobility. This research was designed to study the basic flow mech anisms of polymer solutions in porous media. The interacting effects of polymer properties and porous media properties on flow performance are considered. This study indicates some of the conditions under which these interactions can lead to significant mobility effects. is valid only for Newtonian fluids. For polymer solutions and other non-Newtonian fluids the equation must be modified to consider that viscosity is a variable quantity. Modification of the Darcy equation to include non-Newtonian effects has been the subject of several recent investigations."" The modifications generally adopt a rheological model. such as an Ellis or Dower law model. to Dorous media by defining some characteristic channel radius. Most of these studies showed the porous media flow behavior to be predictable from viscometric data. Investigations involving the flow of high molecular weight polyacrylamide solutions through cores have generally encountered the high flow resistances reported previously by Pye. This high flow resistance has generally been attributed to an in-depth permeability reduction, as evidenced by a reduced permeability to water which has displaced polymer solution from the porous media. Marshall and Metzner" report high flow resistances, which they attribute to viscoelastic effects. In this paper, the effects of polymer molecular weight, pore size, flow rate and concentration are considered. The polymers used are the polyethylene oxides known as Poly-ox. This class of polymers was used because of its availability in a wide range of molecular weights and because of its known ability to propagate well through porous media. THEORY PHYSICAL PROPERTIES OF POLYMER SOLUTIONS The polymer molecule dissolves in water by means of hydrogen bonding, but retains some of its own structural identity while in solution. Nonionic polymers, such as polyethylene oxide, are generally considered to have a random coiling configration. This type of molecule has the ability to "sequester" or hold a large volume of solvent within its coils in a manner similar to that of a sponge. The random coil is easily deformed and under an applied stress

By R. R. Goddard

By use of the frequency response method with a radioactive tracer, it was possible to determine fluid dispersion and distribution in a natural consolidated and an unconsolidated medium. Measurements were made in a linear flow system at oleic saturations of 69 per cent in the consolidated medium, and 100 per cent in both media. Dispersion and distribution were obtained by measuring the amplitude attenuation and the phase velocity of sinusoidal waves with a dual monitor apparatus. The gamma ray emissions permitted in situ measurements at any distance along the porous samples. One result of importance was that the effective diffusivity increased as the wave length increased. As a consequence, a dispersion coefficient appropriate for the injection of large slugs might exceed the value measured by use of small slugs. Since flow models based solely on fluid velocity and an effective diffusivity coefficient imply that the diffusivity should be independent of frequency, such representations were not adequate for the data of this study. A comparison was made with a capacitance model of porous media with deadend PVs, but even this model was not completely adequate. By using attenuation and phase velocity data, fluid dispersion can be predicted without postulating a differential equation satisfied by the tracer concentration, thereby eliminating the need of a complicated model to represent dispersion. INTRODUCTION The flow of similar miscible fluids through a porous medium can be fairly adequately described by two parameters: the average fluid velocity and the effective diffusivity.1-3 It has been pointed out recently, however, that significant discrepancies exist between this representation and the experimental data.4-7 An improved agreement can be obtained by introducing additional parameters based on the concept of dead-end pores. The purpose of the present investigation was to find out whether the frequency response method could be used to measure the relevant parameters. The method was used in the following form. A stream of fluid was flowed at a constant rate through a sample of porous material and the concentration of a radioactive tracer in the fluid was varied sinusoidally at a fixed frequency. The effects of flow through a porous medium are a decrease in the amplitude of the concentration wave and an increase in the velocity of the peaks of the waves above the average velocity. Attenuation and phase veIocity of the waves were measured as a function of frequency and fluid velocity. The simple two-parameter model implies that the diffusivity should be independent of frequency. Data reported in this paper show that the diffusivity decreases as the frequency increases. Hence, as shown also by many others, the two-parameter model is not completely adequate. Coats and Smith 5 used two additional parameters in their model: the volume of the dead-end pores and the rate of mass transfer between dead-end pores and the flowing stream. Their capacitance model of a porous medium containing some stagnant fluid, to which transfer occurs by molecular diffusion, did not explain the dispersion results of either the present study or of theirs. Instead, the capacitance effect can be better described as the result of extreme velocity variations within the pores of the medium, with transfer between the velocity zones by convection. EXPERIMENTAL PREPARATION OF POROUS MEDIA Data reported here were obtained with a natural Berea sandstone, and with two packings of 20/25 mesh sand. Pertinent information about these media is listed in Table 1. The sandstone core was first sealed with a non-

Jan 1, 1967

By P. Datta, L. L. Handy

For a wetting phase displacing a nonwetting phase from a porous medium the distribution of the residual fluid may depend on displacement conditions. Although this subject has been debated in the literature, only a few experiments have been cited to support the various conclusions. Experimental results presented in this paper show that fluid distributions are dependent on imbibition pmcedures. Results agree qualitatively with predictions from the pore doublet model. If the rate of water imbibition is restricted, the nonwetting phase is trapped preferentially in .the larger pores as expected. But if the rate of water imbibition is unrestricted, trapping occurs somewhat more in the smaller pores. These conclusions were deduced primarily from relative permeability measurements. INTRODUCTION Relative permeabilities are known to depend on the saturation history of the porous medium. For either continuously increasing or continuously decreasing wetting phase saturations, however, they have normally been assumed to be single-valued functions of saturation. Severat investigators have compared relative permeabilities measured by different methods and have reported acceptable agreement.1-5 Studies of simple models of the displacement process suggest that the distribution of residual fluids can be influenced by the displacement method. If this is so, relative permeabilities also should depend on the method of displacement. These predictions have not been supported by experimental data. The object of this paper is to investigate experimentally some of the predictions of these model studies. The particular question of importance is whether steady-state and unsteady-state methods should be expected to give the same values of relative permeability. Much of the reported data showing agreement between steady-state and unsteady-state methods have been obtained on un consolidated sand. Johnson, Bossler and Naumann, however, compared steady-state and unsteady-state results for Weiler sandstone and found no significant differences.5 Levine made a detailed study of pressure and saturation distributions for a laboratory waterflood in a consolidated system but made no attempt to calculate performance from steady-state relative permeability data Bail and Marsden in a somewhat similar set of experiments did attempt a comparison of observations with predictions but the results were inconclusive.7 Excluding gravity, two forces affect the distribution of wetting and nonwetting phases during an unsteady-state, immiscible displacement: viscous and capillary forces. If relative permeabilities are indeed the same when measured by steady- or unsteady-state methods, the fluid distributions at the same fluid saturations must be similar for both methods. Furthermore, the implication is that the relation between capillary and viscous forces is the same for both methods insofar as the effect on microscopic fluid distributions is concerned. Unsteady-state displacements are normally run at high rates to maximize the ratio of the viscous to capillary forces. The objective is to reduce the effect of capillary forces on macroscopic fluid distributions. For floods in which the phase which wets the porous medium displaces the nonwetting phase, capillary forces compete with viscous forces in determining fluid distributions.8 The residual nonwetting phase is discontinuous. Competitive aspects of viscous and capillary forces and the resulting effect on water-oil distribution in porous media have been illustrated in an elementary way using a pore doublet model. This model and predictions from it have been discussed at considerable length by Rose and Witherspoon, Rose and Cleary and by Moore and Slobod.9-13 Rose and Witherspoon show that so long as water invades the model at a rate equal to or greater than the free imbibition rate, the water will move through the larger capillary of a doublet first and trap oil in the smaller capillary. On the other hand, if a negative pressure is applied to the water

Jan 1, 1967

By R. W. Parsons, P. R. Chaney

Oil recovery by the imbibition mechanism can be important in fractured carbonate reservoirs with a bottom water drive. Laboratory experiments were performed on water-wet carbonate rocks to model this process. The results are interpreted in light of the applicable scaling laws. The imbibition production behavior of a pillar of rock subjected to a slowly rising water table can be synthesized from data on total immersion experiments on small rock samples. If the rate of water table rise is slow enough and if the physical properties are such that the imbibition zone is of a small vertical extent, then only the final oil recovery on the small samples need be known. Applying laboratory imbibition data to a real reservoir should be done with caution because of possible wettability problems and the unknown behavior of two-phase flow in fractures. INTRODUCTION The spontaneous taking up of a preferential wetting fluid into a porous medium with the simultaneous expulsion of the contained fluid is termed imbibition. One of the many physical imbibition processes is the production of oil by the taking up of water into a water-wet reservoir rock. In certain types of heterogeneous reservoirs, e.g., fractured, it is realized that imbibition alone may be the dominant mechanism. Theoretical studies of imbibition oil recovery have followed several lines of attack. The behavior of certain mathematically tractable and conceptually simple models have been analyzed. Birks1 considered a bundle of vertical capillaries model, while Perotti et al.2 and Kelemen3 used a model of a series of vertically oriented fractures. If the oil production behavior from a block of reservoir rock is known, then the cumulative behavior of a vertical stack of these blocks subjected to a rising water table can be determined by a method outlined by Aronofsky et al. 4 Knowing the capillary pressure and relative permeability functions should uniquely set the imbibition behavior for a given sample. Solutions of the partial differential equations describing the process, however, present some formidable problems. Digital computer techniques have been applied to displacement processes in which the capillary pressure has been included.5"8 More recently, similar techniques have been used by Blair 9 to calculate countercurrent imbibition behavior. The fact that imbibition behavior is described by the usual fluid flow equations (Darcy's Law and continuity equation) implies that the derived scaling laws should apply equally to this situation. Use of model experiments to study imbibition has been employed by Graham and Richardson 10 and Mattax and Kyte,11 who actually tested the scaling law applicability. This study is concerned with scaled model imbibition experiments on water-wet carbonate rocks. Of particular interest is the slowly rising water table experiment. This simulates a highly fractured reservoir with the water table rising uniformly through the vertical fracture system. Experiments were performed on different sized samples and with different rates of rise of the water-oil interface surrounding the rock pillar. Total immersion imbibition experiments on smaller rock samples were performed to test the basic linear scaling laws and to see if these simpler tests could be used to synthesize the rising water table experimental results. THEORY IMBIBITION SCALING LAWS Scaling laws for the flow of two incompressible immiscible fluids in a porous medium have been presented by Rapoport.12 These are derived directly from Darcy's Law for the individual phases and the continuity equation. Results from a laboratory model experiment will duplicate those from some reservoir prototype if a constant proportion is maintained among the three forces acting on the fluids — the capillary pressure gradient, the gravitational gradient and the flowing pressure gradient. Operation of the model (i.e., fluid injection or withdrawal) must be conducted in accordance with specific equations. If the

Jan 1, 1967

By N. Mungan

A study was made of the effects of wettability and interfacial tension on the immiscible displacement of a Iiquid by another Iiquid from porous media. The influence of viscosity ratio was also investigated. Porous media used were polytetrafluoroethylene (TFE) cores prepared by compressing TFE powder under different pressures. lt is shown that displacement of a wetting by a nonwetting Iiquid is always less efficient than the displacement of a nonwetting by a wetting fluid, all other things being equal. In the former case, the recovery efficiency can be increased substantially by either reducing the interfacial tension or increasing the viscosity of the displacing fluid. A qualitative discussion is given on the implications of this work to the recovery of crude oil by water flooding. INTRODUCTION The high cost of oil exploration and new recovery schemes makes it imperative that waterflooding be conducted under conditions favoring most efficient oil recovery. To improve oil recovery by waterflooding, it is essential that the role played by interfacial forces in the entrapment of residual oil be studied and understood. Interfacial phenomena in natural rock, connate water and crude oil systems are very complicated because of the complexity of the natural liquids found in petroleum reservoirs, because of our inability to adequately describe the geometrical structure of the porous media and because of a lack of understanding of physical and chemical interactions between the liquids and surface of the pores. The problem becomes further complicated when one tries to elucidate the role of interfacial phenomena in fluid flow. Numerous studies of the displacement of oil by water under different interfacial tension or wet-tability conditions have been made.lm3 These studies have been performed in silica, alundum or sandstone systems using water and paraffin oil and also some surface active material to control the interfacial tension s and the contact angle 0. Unfortunately, the high energies of various interfaces involved favor adsorption and orientation of the surface active material at the interfaces. Also the surface active material concentration at the interfaces exceeds that in the bulk of the liquid phases. Such surface excess may cause the surfactant distribution, the contact angle and the interfacial tension to differ from their measured static equilibrium values and makes interpretation of the displacement experiments difficult. Furthermore, as changes in s also lead to changes in cos 0, the role played individually by one of these parameters in the displacement becomes obscured by the effect of the other. To circumvent these difficulties, a low surface energy solid and true solutions or pure liquids should be used. Use of a low surface energy solid minimizes adsorption and orientation effects at the solid-liquid interfaces. By controlling s and cos 0 through use of selected pairs of pure liquids or true solutions rather than by surfactants, the adsorption effects at liquid-liquid interfaces are eliminated. In the present study TFE cores were used as the porous media. Liquids used were water, sucrose solutions, paraffin oils and benzyl, n-butyl and isobutyl alcohols. The interfacial tension was varied from 40 to 1.1 dynes/cm by suitably choosing the liquid pair. A surface active material was added to the water-oil system only in the case where interfacial tension of 0.5 dyne/ cm was desired. No precise changes of cos 0 were attempted. However, either the displaced or the displacing liquid could be made the one which preferentially wets the TFE surface. Using sucrose solutions and blends of paraffin oils proved to be a convenient way of changing the viscosity ratio between the displaced and displacing liquids. The present investigation examines the effect of interfacial tension, wettability and viscosity ratio on the immiscible liquid-liquid displacement from porous media. Observed data permit a

Jan 1, 1967

By W. B. Gogarty

With the use of polymer solutions in secondary recovery operations, the need has developed to understand the mobility control mechanism. This study investigated mobility control by considering both permeability and rheological effects. Experiments used a high molecular weight, partially hydrolyzed polyacrylamide polymer. Flow studies took place in reservoir and Berea cores having zero oil saturation. Effective size of the polymer flow unit was inferred from Nuclepore filter tests. Clay studies indicated the particle size capable of decreasing the core permeability. Flushed permeabilities measured the approximate core permeabilities with flowing polymer solutions. These permeabilities were considerably lower than original values. With mobility data and the flushed permeability, maximum effective viscosities were determined for polymer solution flow in a core. Effective viscosities showed that rheological properties play an important part in mobility control with polymer solutions. The study showed that permeabilities decrease and stabilize with polymer flow. At the lower permeabilities, high shear rates exist in the cores. Because of the pseudoplastic character of the polymer solution, the high shear rates caused low effective viscosities. This condition pointed to the inefficient use of the potentially high viscosity of the polymer solution at low shear rates. INTRODUCTION In the oil industry, a great deal of interest is being shown in the use of polymer solutions for secondary recovery and a number of polymer floods are being performed in the United States.1 Some of these floods have become commercial while others have been reported as failures. A number of floods are still in progress and remain to be evaluated. With the advent of polymer flooding, the need developed to understand the mobility control mechanism in porous media. Rheologically, the polymer solutions behave as pseudoplastic fluids. Investigators have studied the rheology for this type of non-Newtonian fluid in porous media?-6 Results have also been reported on the ability of polymer solutions to decrease mobility.7-10 Some investigators indicated that polymer solutions show a different rheological behavior in cores than on the viscometer.7,8 This study is representative of an initiatory investigation on mobility control with polymer solutions. Some effects are considered on a qualitative basis. Mobility control is considered from the standpoint of both permeability and rheology and, to the extent possible, permeability and rheological effects are considered separately. Results show that mobility control occurs from a reduced permeability caused by polymer retention and an effective viscosity determined by the average shear rate in the core. In this respect, rheological behavior is as important in mobility control as permeability. PROCEDURES A high molecular weight, partially hydrolyzed, polyacrylamide polymer was used in the investigation. Solutions of various concentrations were made with this polymer in different types of water. Some solutions used distilled water and others used tap water. The tap water contained approximately 500 ppm dissolved solids. As used in this paper, concentrations in ppm refer to parts by weight solute to one million parts by weight of solvent. In the tap water, calcium and magnesium accounted for from 60 to 80 ppm of the solids, the remainder being mostly sodium chloride. All solutions contained a bactericide, and anti-oxidants and antiprecipitants were added to the tap water. Capillary and concentric-cylinder* viscometers determined the rheological properties of solutions. The capillary viscometer is described elsewhere.6 Berea and reservoir sandstone were used as core materials for this investigation. Cores were 1 in. in diameter by approximately 2 to 3 in. long. Prior to mounting, the Berea cores were heat-treated for 3 hours at 850F. This treatment decreased the water-sensitivity of the clays in the cores. The reservoir cores were cleaned with solvent and

By A. R. Gregory

A shear wave velocity laboratory apparatus and techniques for testing rock samples under simulated subsurface conditions have been developed. In the apparatus, two electromechanical transducers operating in the frequency range 0.5 to 5.0 megahertz (MHz: megacycles per second) are mounted in contact with each end of the sample. Liquid-solid interfaces of Drakeol-aluminum are used as mode converters. In the generator transducer, there is total mode conversion from P-wave energy to plain S-wave energy. S-wave energy is converted back to P-wave energy in the motor transducer. Similar transducers without mode converters are used to measure P-wave velocities. The apparatus is designed for testing rock samples under axial or uniform loading in the pressure range 0 to 12,000 psi. The transducers have certain advantages over those used by King, 1 and the measurement techniques are influenced less by subjective elements than other methods previously reported. An electronic counter-timer having a resolution of 10 nanoseconds measures the transit time of ultrasonic pulses through the sample; elastic wave velocities of most homogeneous materials can be measured with errors of less than 1 percent. 5- and P-wave velocity measurements on Bandera sandstone and Solenholen limestone are reported for the axial pressure range 0 to 6,000 psi and for the uniform pressure range 0 to 10,000 psi. The influence of liquid pore saturants on P- and S-wave velocity is investigated and found to be in broad agreement with Biot's theory. In specific areas, the measurements do not conform to theory. Velocities of samples measured under axial and uniform loading are compared and, in general, velocities measured under uniform stress are higher than those measured under axial stress. Liquid pore fluids cause increases in Poisson's ratio and the bulk modulus but reduce the rigidity modulus, Young's modulus and the bulk compressibility. INTRODUCTION Ultrasonic pulse methods for measuring the shear wave velocity of rock samples in the laboratory have been gradually improved during the last few years. Early experimental pulse techniques reported by Hughes et al.2 and by Gregory 3 were beset by uncertainties in determining the first arrival of the shear wave (S-wave) energy. Much of this ambiguity was caused by the multiple modes propagated by piezoelectric crystals and by boundary conversions in the rock specimens. Shear wave velocity data obtained from the critical angle method, described by Schneider and Burton4 and used later by King and Fate sand by Gregory, 3,6 are of limited accuracy, and interpreting results is too complicated for routine laboratory work. The mode conversion method described by Jamieson and Hoskins7 was recently used by King 1 for measuring the S-wave velocities of dry and liquid-saturated rock samples. Glass-air interfaces acted as mode converters in the apparatus, and much of the compressional (P-wave) energy apparently was eliminated from the desired pure shear mode. A more detailed discussion of the current status of laboratory pulse methods applied to geological specimens is given in a review by Simmons.8 A new shear wave velocity laboratory apparatus has been developed for testing rock samples under elevated pressures. This apparatus employs liquid-solid interfaces as mode converters. The technique for generating pure shear waves at liquid-solid interfaces was developed from studies of critical angle methods.6 Two identical transducers are placed in contact with opposite ends of the rock sample, one transducer acting as an ultrasonic energy emitter or generator and the other acting as an ultrasonic energy receiver or motor. The P-wave energy emitted from the piezoelectric crystal in the generator transducer is converted into pure S-wave energy at the Drakeol-aluminum