Search Documents

By C. R. Clark, G. Swift, D. S. Roberts

The purpose of this investigation was to measure PVT behavior of various types and combinations of heavy hydrocarbon components from the paraffinic, naphthenic and aromatic classes where the relative proportions Of the various components were selected to approximate those of natural gas or gas condensate systems. Synthetic mixtures were used so that the compositions Of the various components could be measured accurately. n-Heptane, methylcyclohexane and methylbenzene were used to represent the paraffinic, naphthenic and aromatic components of the heavy fraction. In the mixtures studied, the heavy fraction composition was held constant at O. O5-mole lraction, the balance being methane except for one mixture where 0.10-mo1e fraction of an intermediate component, propane, was added. The PVT data for the mixtures were determined in a variable-volume, constant-mass apparatus at psuedo-reducedtemperatures from 1.84 to 2.00, over a pseudo-reduced pressure range from 2.3 to 12.0. The experimental results showed that, regardless of the type of heavy material (paraffinic, naphthenic, aromatic, or combinations thereof) mixed with methane or methane and propane, the compressibility factors at equal values of pseudo-reduced temperature and pressure varied by less than 2.2 percent. INTRODUCTION PVT data is used for natural gas and gas condensate fluids in determining reserves of reservoirs and performance of wells, in metering produced fluids, and in recombining samples for laboratory studies. While there are vast amounts of PVT data reported for natural gas and gas condensate systems from which useful correlations have been developed, ' the compositional analyses for these systems and the resultant correlations typically were made with components analyzed through some arbitrary carbon number, usually C6, with the residue reported as a lumped "heavy" fraction. The heavy fraction was stoichiometrically recombined on the basis of an apparent molecular weight to give the final compositional analysis. It is virtually impossible to make a systematic analysis of the effect that variation of the relative amounts of paraffinic, naphthenic and aromatic constituents of the heavy fraction of natural systems might have on PVT behavior. Because there is considerable latitude in the relative amounts of these constituents, one speaks of crudes or condensate liquids as being "paraffin base", etc. It is of interest to determine if changes in the relative amounts of these three types of hydrocarbons in the heavy fraction cause significant changes in PVT behavior. If so, steps should be taken to describe better the nature of the heavy fraction in PVT correlations. If not, more confidence can be placed in the correlations presently employed. DESIGN OF THE EXPERIMENTAL INVESTIGATION We attempted to determine if changes in the base of the heavy fraction would cause significant changes in the PVT behavior of gas or gas condensate fluids. Synthetic mixtures were used to enable us to systematically vary the base of the heavy fraction and to analyze accurately the fluids. We found that the heavy fraction of naturally occurring condensate systems seldom exceeds 0.05-mole fraction. Thus, the mole fraction of the heavy fraction in the synthetic systems studied was set arbitrarily at 0.05, to maximize whatever deviations in PVT behavior that might occur. Further, we judged that since the C7 hydrocarbons normally are present in greater quantities than higher carbon number hydrocarbons in naturally occurring systems, the use of n-heptane, methyl cyclohexane, and methylbenzene to represent the paraffinic, naphthenic, and aromatic species in the heavy fraction would be most appropriate. Finally, to enable us to compare our

Jan 1, 1970

By C. C. Mattax, J. E. Bobek, M. O. Denekas

ABSTRACT investigations in recent years have shown that rock wettability can exert a profound influence on the displacement of oil by water from oil producing reservoirs. Core analyses frequently show oil recoveries from preferentially water-wet rock to be significantly greater than those from preferentially oil-wet rock. Thus, an accurate prediction of water-drive or waterflood oil recovery is dependent on the evaluation of reservoir rock wettability. Laboratory and field studies have been undertaken to examine and develop methods which may be used to measure rock wettahililiy, to investigate factors which may alter the wettability of reservoir rock, and to determine the wettability of specific reservoirs. It has been found that measurement of the rate and volume of spontaneous imbibition of the wet-ting phase by a rock is a reliable and reproducible test for semi-quantitarive determination of preferential rock wettability. Laboratory tests have shown that the wettability of reservoir rock may depend on both the crude oil composition and the rock type. Field and laboratory tests have indicated that coring flulids and core handling techniques can cause significant changes in the wettability of rock surfaces. However, a few fluids, brine in particular, appear not to affect core wettability and may be used when coring to determine reservoir wettability. Core handling and packing procedures have been developed which preserve core wettability during storage and laboratory testing. The wetfability characteristics of six reservoirs have been evaluated by wettabilify tests performed in the field on fresh cores cut with brine or special water-base muds. The tests indicated that all six reservoirs are water wet; however, the de-gree differed from one reservoir to another. INTRODUCTION Although surface properties of reservoir rock and interfacial characteristics of rock, crude oil, and water systems have been discussed for many years, the full significance of these properties to the production of oil is still in the process of evaluation. It is known, however, that one surface characteristic—preferential wettability of the reservoir rock—-is of paramount importance when the reservoir is being produced by water-flood or water-drive mechanisms. The importance of rock wettability has been pointed out by several authors'.',%* who have found that pref- erentially water-wet cores flood more efficiently than oil-wet cores; that is, more oil is recovered from water-wet cores in the early flooding stages than from oil-wet cores. Other authors'," indicate that waterflood oil recovery from cores of intermediate wettability may be greater than that from either strongly water-wet or strongly oil-wet cores. These recent investigations emphasize that the true wettability of a reservoir must be known before the performance of waterflood or water-drive reservoirs can be accurately evaluated. When reservoir wettability is to be determined by core analysis, precautions must be taken to maintain the original wettability which can be altered readily during coring5 nd testing.' In the coring operation the core may be partially or completely penetrated by the drilling fluid which, if it contains surface active materials, may drastically change the wettability of the core. Also, improper core handling during stcrage and testing may change its wettability because of evaporation of fluids or exposure to oxygen or surface active contaminants. One purpose of this paper is to discuss methods for obtaining, preserving, and testing cores without altering their original wettability. In addition, the results of wettability tests on fresh and preserved cores from six reservoirs are presented where special precautions were taken to obtain samples without altering their wettability during the coring operation.

By L. V. Pirela, S. M. Farouq Ali

Some interest has been expressed recently in the application of solvents in conjunction with a thermal drive, such as a steamflood. At least one field project of this type has been reported. This paper makes the first attempt to provide some of the basic information necessary for choosing a solvent for such an application. Results of displacements conducted at elevated temperatures are also discussed. This paper shows that, in the case of alcohol-hydrocarbon-water or brine ternary systems, the system miscibility may increase, decrease, or both increase and decrease within the same system when the temperature increases. The distribution coefficient was consistently found to increase in favor of the oleic phase with an increase in temperature, which is advantageous from the standpoint of oil recovery. Results of solvent displacements in a sandstone core showed that even a relatively small temperature effect in the favorable direction (increase in miscibility and distribution coefficient) can lead to a 50 percent increase in oil recovery. On the other hand, if the system miscibility decreases with the temperature, even though the distribution coefficient increases, the oil recovery at the higher temperature may not increase. INTRODUCTION Miscible displacement has been the subject of many investigations. Miscible-phase solvent flooding, employing solvents such as alcohols that are miscible with both oil and water, has received considerable attention. Investigations conducted by Gatlin and Slobod,l Taber, Kamath and Reed,2 Holm and Csaszar,3 and Farouq Ali and Stah14 have helped in understanding the mechanism of solvent flooding. While the use of alcohols and similar solvents as oil recovery agents is economically unattractive, these solvents nevertheless provide a means of understanding the mechanistic aspects of important miscible-phase oil recovery processes such as the Maraflood process (discussed by Gogarty5). As shown by Taber et a1.,2 the phase behavior of a solvent-oil-water system is of .utmost importance in determining the efficiency of the oil displacement. This paper makes the first attempt to obtain the ternary phase behavior data for nine alcohol-hydrocarbon-water/brine systems at elevated temperatures. Results of core tests at elevated temperatures are also presented which corroborate the effect of temperature on oil recovery, as judged on the basis of phase-behavior data. The use of solvents at elevated temperatures has been suggested earlier by Farouq Ali.6 At least one field test of this type has been reportedO7 With the widespread use of thermal recovery techniques, it is possible in some situations (especially in steamflooding) that the use of a suitable solvent in conjunction with the heat carrier may be economically feasible. This paper attempts to provide some of the basic information needed for judging such feasibility. LOCATION OF THE PLAIT POINT The phase behavior of a typical ternary system consisting of a solvent, hydrocarbon and brine (or water) can be represented by a triangular diagram such as the one shown in Fig. 1 (for temperature TI). Point Pon the binodal curve represents the plait point, being the limit of tie lines such as Y1 Y2 The compositions of the coexisting oleic and aqueous phases are given by points Y2 and Y1, respectively, for any mixture composition along Y1Y2. The characteristics of ternary diagrams have been discussed by Findlay8 and others. Taber et aL3 have shown that the position of the plait point in a particular ternary system plays the decisive role in determining whether or not theoleic phase would be displaced in a continuous manner during an alcohol displacement. The area above the binodal curve also is important, since it represents

Jan 1, 1969

By L. B. Davidson

The petroleum literature contains many reports on the relative permeability properties of porous media. However, only recently have studies of relative permeability at elevated temperatures been made.1 -5 Each of these studies presents relative permeability data on water-oil systems in linear sandpacks or sandstone cores under isothermal conditions. The results of these investigations are dissimilar. Edmondsonl found that in Berea sandstone a temperature-dependent effect was present, while Shilobod,2 using the same material, found no temperature dependence after normalizing for initial water saturation. Workers at Texas A&M U.3-5 found that the ratio kw/ko was temperature dependent in an unconsolidated system. The differences in results of these studies are probably a consequence of differences in the material employed, in the experimental procedures followed, and in the properties of the porous systems used. This paper describes an experimental investigation of permeability ratio temperature dependence, conducted to clarify some of the results obtained by previous workers. Each experiment described in this paper involved the isothermal displacement of Chevron No. 15 white oil by either nitrogen, steam, or distilled water and displacement of water by nitrogen. All permeability ratios were calculated using the Welge procedure. Values of the water-oil permeability ratio were obtained over the temperature range 75OF to 540°F. Results indicate the ratio is temperature dependent at low water saturations, probably due to interfacial effects. However, as the saturation is increased, temperature dependence decreases until, above some minimum saturation, the ratio becomes insensitive to temperature. Previously published work indicates that the dependence reappears at very high water saturations, a region of the ratio curve not completely examined in the present study. It appears that water-oil permeability ratios are temperature dependent at the extremes of the ratio curve where changes in interfacial tension with temperature induce variations in residual saturations. Between the extremes, there is a region in which the permeability ratio is insensitive to temperature. The size and location of this region is probably a function of the characteristics of the porous system. Gas-oil permeability ratios calculated from nitrogen-white oil displacement experiments indicate a definite temperature dependence over the range 75OF to 500°F and over the entire gas saturation range studied. Evidence discussed in this report indicates that this dependence is a consequence of molecular slippage in the gas phase. This is an extension of the Klinkenberg effect6 to two-phase systems at high temperatures (the existence of slippage in two-phase systems at room temperature has been demonstrated7). Evidence for a similar source of temperature dependence in superheated steam-white oil experiments

Jan 1, 1970

By C. W. Volek, J. E. Chappelear

The injection of a hot liquid into initially cool porous media, saturated with the same liquid and surrounded by two impermeable but heat conducting media (cap and base rock), has been studied both experimentally and theoretically. The temperature dependence of the viscosity was included in the theoretical model, but it was assumed that the specilic heats and densities of the various materials were independent of the temperature. Solutions to the theoretical model were approximated by numerical methods. Both theoretical and experimental results indicate that center-line temperatures are significantly higher than boundary temperatures. Comparison of experimental and theoretical results with a cold/hot viscosity ratio 01 19:1 were in reasonable agreement. Theoretical calculations show that the effect of the temperature dependence of viscosity was very significant at ratios of 100:l to 1000:1, which are typical of those that occur when injecting hot water to flood heavy oil reservoirs. INTRODUCTION We consider the problem of prediction of fluid flow and temperature distribution in an initially cold-fluid-filled reservoir on the injection of the same hot liquid by the use of mathematical and physical models. The results reported are for a two-dimensional rectangular section of the reservoir, as shown in Fig. 1. The injection and withdrawal faces are assumed to be equipotentials for fluid flow. The ultimate purpose of such models would be to predict hot-water injection performance. However, we note that in the work presented here, one of the most significant aspects of the problem — the instabilities resulting from two-phase, water and oil flow — is not included. We will not give a historical review, but refer instead to the paper of Spillette and Nielsen,1 which contains a rather complete bibliography and critical discussion. The physical problem is exactly the same as Spillette and Nielsen, except for certain simplifications in our assumptions. The mathematical details are somewhat different, and we will present the details of our method here. The mass flow equation, which is elliptic in character, is handled by successive overrelaxation. The heat flow equation, which is parabolic in character, is handled by a straightforward explicit approximation. Some difficulty arose in the over-all heat balance due to small errors in the solution of the mass flow equation, and we feel that a different formulation of the heat flow equation would be desirable for future work. In addition to the mathematical solutions for the temperature distributions in a porous medium due to the injection of hot liquids, experimental data are presented to check the validity of these solutions. A schematic diagram of the model is shown in Fig. 2. Certain qualitative physical conclusions were obtained from our numerical and experimental results. These are: 1. Assuming high (infinite) conductivity normal to the bedding plane in the reservoir is a poor approximation, and may lead to overestimates of the total heat losses (to cap and base rock) of as much as 50 percent. 2. More heat is retained in the reservoir (per unit of heat injected) for higher viscosity changes. 3. Any particular temperature isotherm moves more rapidly along the center line for higher viscosity changes. Consequently, the approximation of temperature independent viscosity is not suitable for obtaining quantitatively correct results. MATHEMATICAL MODEL Our mathematical model is that of a reservoir of thickness 2h. The problem is idealized from that of a linear hot-water drive, and we imagine that the input face is sufficiently far away from the injection wells that the stream lines enter it normally. Similarly the production wells are far enough from the outflow face that the flow lines leave it normally. The reservoir and surrounding cap and base rock

Jan 1, 1970

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 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 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 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

By C. Dirksen

This study investigates whether oxygen consumption during segregated forward combustion may be affected by natural convection. Linear theory indicates that thermal instability occurs in a horizontal porous medium when the modified Rayleigh number N 'Ra exceeds a critical value of about 40. Most experimental results, including those described here, indicate this value to be about an order of magnitude smaller. N ', is derived from "differential similarity" and the proper time scale factor is also obtained. The critical value of N'ra for a horizontal, water-saturated porous medium at atmospheric pressure subjected to a uertical temperature gradient was found to be about 3.0. The ambiguity in the value of N'R, arising when fluid properties cannot be assumed constant is indicated. Natural convection was observed for oblique systems below N 'Ra , while simultaneous horizontal flow did not affect N Racrit. The expected range of values for the various parameters pertaining to segregated forward combustion is indicated and the corresponding values of N 'Ra calculated. Only under very favorable conditions, such as high permeability, high pressure and low top temperature, can the critical value of N 'R, be exceeded. Thickness of the convection layer should not become too large, since the time required to obtain significant mixing is proportional to the square of the thickness. For an oblique combustion frant the conditions for significant mixing may be less strenuous. LNTRODUCTION Laboratory1,2 and field314 experiments have shown that a markedly upgraded oil can be produced by in situ forward combustion. Under certain conditions injected air may move through a high permeability, gas-saturated channel over the oil-saturated layer, while combustion takes place, exclusively, at the horizontal interface (Fig. 1). Such a channel may be a natural gas cap, or it may result from a forward combustion process in which injected air and combustion gases fingered through the top of the formation, causing a premature breakthrough at the production well. In this particular case of segregated forward combustion, the air stream moves parallel to the combustion front. Molecular diffusion and transverse mechanical dispersion will be insufficient to cause all the oxygen in the air stream to reach the combustion front. When the oxygen in the air stream is not completely consumed in the combustion process, it will reach the production well and create a serious fire hazard. In addition, the reduced efficiency may make the process economically unprofitable while also serious corrosion problems may be experienced in the production we11.3 This undesirable situation should, therefore, be prevented. However, in a situation as depicted in Fig. 1, an unstable temperature gradient exists in the gas phase. The combustion is taking place at the lower boundary at a nearly constant temperature that may be anywhere from 600 to 1,200F, depending on the conditions. The upper boundary of the gas phase is overlying, impermeable rock; its temperature might be around 100F, but may increase to 300F or higher due to conduction and convection as the combustion process continues. This represents a steep temperature gradient and it is conceivable that under those conditions free or natural convection will take place in the gas

Jan 1, 1967

By N. Mungan, F. W. Smith, J. L. Thompson

Adsorption of polymers and transport, rheology and oil recovery efficiency of their solutions were studied in the laboratory to evaluate the use of polymers in waterflood-ing. While a tenfold mobility reduction was obtained with polymer concentrations as low as 0.05 per cent by weight, the mobility reduction depended on the type of polymer, molecular weight, salinity and pH of water, crude oil and capillary properties of the porous media. Choice of a suitable polymer and a workable concentration will have to be tailored for each application. Little reduction in the residual oil saturation can be expected from polymer flooding. Improvement in the volumetric sweep efficiency is possible hut the extent of the improvement can best be evaluated by properly designed field testing. Some aspects of the field use of polymer floods are discussed. INTRODUCTION Waterflooding is a simple, inexpensive secondary recovery method and is being used widely. Innumerable laboratory studies have been made to unravel the fundamentals of the displacement of oil by water and to find the ways of most efficient oil recovery. These studies and a great many field case histories have revealed that the prime cause of poor oil recovery is the inefficient and incomplete sweep of reservoir volume by the injected water. Sweep efficiency is affected by many factors of which the mobility ratio is an important one. Mobility ratio M is defined here as the ratio of water to oil mobilities: M = (k»/y,r)/(k,JJJJ........(1) In Eq. I, the permeabilities are the effective permeabilities and depend on fluid saturations and, hence, change during the different depletion stages in a flood. A wide practice is to use the effective water permeability at residual oil saturation and the effective oil permeability at interstitial water saturation in Eq. 1. If the mobility ratio is greater than one, the mobility ratio is unfavorable and water, being more mobile than oil, would finger through the oil zone resulting in poor oil recovery efficiency. If the mobility ratio is favorable (one or less) the displacement of oil by water occurs more or less in a pistonlike fashion. In some waterfloods. the mobility ratio is unfavorable and any additives by which the mobility of water can be decreased would favor more efficient oil recovery. The thing to bear in mind, however, is whether or not the improvement in oil recovery is sufficient to more than pay out the cost of the additives needed. For example, materials like sugars, alcohols and glycerine reduce water mobility by thickening the water, but the cost of material requirement precludes any field application. For an additive to be useful in water-flooding, it must bring about a large reduction in water mobility at low concentrations; it must be adsorbed only negligibly; and it must not completely plug up the formation. Some synthetic organic polymers have shown promise of meeting these requirements and have been used in the field.'-W owever, no in-depth studies of the rheological, adsorption and oil displacement characteristics of polymer solutions have been reported. The present work is a study of these properties. EXPERIMENTAL In this work, concentrations are given on a weight per volume basis; 0.5 per cent concentration means 0.5 gm of polymer is dissolved in enough water (or NaCl solution) to make 100 ml. A bactericide, usually 0.1 to 0.2 per cent by volume of 38 per cent formaldehyde solution, was used in the polymer solutions. The NaCl solution was 30,000 ppm. Some properties of the polymers studied are given in Table I. Physical properties of all cores used are in Table 2. Flow behavior of polymer solutions was studied by three consecutive flow tests in cores. First, water (or brine) was injected at constant rate of about 1 ft/D to obtain the water mobility. Then, filtered polymer solution (prepared in water or brine) was flowed through the core. Since the rate was constant, increase in the pressure drop across the core reflects decrease in the mobility. Finally, the core was flooded with water (or brine) to study recovery of mobility. The Alundum cores which were used in

Jan 1, 1967

By G. W. Thomas

Jan 1, 1967