This paper describes a series of laboratory caustic (NaOH) waterfloods and related measurements using crude oils from 19 oil reservoirs. These were light (mostly,>30 degrees API) crudes mainly from South Louisiana and Texas, although crude oils from other areas also were tested. The waterfloods held core material (Berea sandstone), connate water (2-percent-NaCl brine) and other conditions (temperature, flow rate, aging time before flood) constant, and determined increased production due to NaOH injection for each crude oil. Relative permeability end-points before and after flooding were used to estimate initial and final wettabilities and, together with crude-oil acid numbers and interfacial tensions against NaOH solution, to infer the probable mechanism by which increased recovery was obtained. A series of laboratory NaOH depletion measurements by static and dynamic methods in core material from several oil-producing formations and in Berea sandstone is also described. Results are compared with those from similar measurements using pure clays and other minerals and with X-ray diffraction analysis of the core material. The following are observations from these tests.Crude oils with acid numbers greater than about 0.1 to a 0.2 mg KOH per gm of oil or interfacial tension against 0.1 percent NaOH less than about 0.5 dyne/cm gave significant caustic-waterflood increased production. There was no further correlation of increased production at higher acid numbers or lower interfacial tensions nor was there a correlation with the apparent initial rock wettability.Regardless of initial wettability or increased production, the cores are indicated to be water-wet production, the cores are indicated to be water-wet following NaOH waterflooding to a high water-oil ratio (WOR).Caustic consumption by reservoir rock is predictable from the formation mineral composition predictable from the formation mineral composition as determined by X-ray methods. Exceptions are noted where clay content is high and where trace amounts of gypsum are present. Introduction Crude oils containing naturally occurring organic acids will react with aqueous caustic solution to produce surface-active materials. These surfactants, produce surface-active materials. These surfactants, when generated during a caustic waterflood, can improve oil recovery over that of a normal waterflood by a number of mechanisms related to changes occurring at the oil-water and liquid-solid interfaces: interfacial-tension lowering, wettability change, changes in interface rheology, etc. The extent to which any of these mechanisms will be operative and the recovery improvement obtainable depends on, among other things, the amount and type of acids present, the initial formation wettability, the reservoir-rock pore geometry, and the extent to which it consumes caustic. The available literature describing mechanisms proposed for caustic-waterflooding improved recovery, proposed for caustic-waterflooding improved recovery, the conditions required for applicability, and the results of various laboratory and field studies have been surveyed most recently by Johnson. Some common currents of thought or implication in this literature and some common areas of uncertainty related to the effects of crude oil and reservoir rock properties on recovery mechanisms are listed below. properties on recovery mechanisms are listed below.The presence of acids in crude oil at some minimum level is an obvious necessary condition for improved recovery. Where emulsification is involved, minimum acid numbers ranging from 0.5 to 1.5 mg KOH per gm of oil have been suggested. No minimum has been stated for other recovery mechanisms. One might not expect such minimum requirements to be absolute since the quality of surfactants generated from these acids can vary widely among crude oils.Improved recovery by wettability alteration generally has been discussed in terms of a reversal from oil-wet to water-wet or vice versa. It has been implied that wettability reversal is required since capillary forces trapping oil are eliminated as the neutral wettability condition is traversed. SPEJ P. 263

This procedure, in which the wettability change is assumed to be the important enhanced recovery mechanism, is recommended for determining the applicability alkaline waterflooding in specific light-oil reservoir systems. Introduction The wettability of petroleum reservoir rock, its estimation in laboratory tests, and its effect on the displacement of oil by water have been the subject of a considerable and growing body of literature. Craig presented an excellent review of developments in this presented an excellent review of developments in this field so another discussion will not be given here. Recent investigators generally agree that preferred wettability is not a discrete-valued function, oil-wet or water-wet, but can span a continuum between these extremes. It has been demonstrated with artificial wettability systems using low-viscosity oils that waterflooding to a given water-oil ratio (WOR) becomes increasingly more efficient as a sand becomes more water-wet. It is not altogether certain, however, that waterflooding under strongly water-wet conditions is always most efficient in real reservoir systems. An example of this is given by Salathiel, who found lower residual oil saturations in mixed wettability systems than would occur under strongly water-wet conditions. This effect was attributed to gravity drainage across bedding planes. Most recently, Treiber el al. noted that a large number of reservoirs are more oil-wet than water-wet.It has generally been found, however, that causing a reservoir to become more water-wet by chemical means during the course of a waterflood results in an increase in oil recovery over that of an unaltered displacement by water alone. This has been demonstrated by Wagner and Leach, and by Leach et al. using a refined oil containing an amine to simulate an oil-wet system and an aqueous acid solution to reverse wettability. Mungan and Emery et al. obtained the same result using a sodium hydroxide (NaOH) solution to alter the wettability of a crude oil-brine-sand system. Alkaline waterflooding has been found under certain circumstances to increase oil production by low interfacial tension displacement and by rigid film breaking as well as by favorable wettability alteration.Two types of screening procedures for recovery estimation have been reported, both of which attempt to duplicate reservoir wettability by contacting oil, water, and mineral for long periods of time. A contact-angle measurement technique was described for wettability and wettability alteration estimation and for wettability estimation alone. The measurement is made after water displaces oil from a plane mineral surface in contact with the oil for various times. To obtain no further changes, the aging times required varied from 200 to 2,400 hours for different reservoir systems. The amount of additional oil obtainable by an alkaline waterflood is inferred from the difference between the normal water-oil-solid and alkaline water-oil-solid contact angles. This type of test can only estimate wettability-change increased production. production. JPT P. 1335

A consolidated porous medium is mathematically modeled by networks of irregularly shaped interconnected pore channels. Mechanisms are described that form residual saturations during immiscible displacement both by entire pore channels being bypassed and by fluids being isolated by the movement of an interface within individual pore channels. This latter mechanism is shown to depend strongly on pore channel irregularity. Together, these mechanisms provide an explanation for the drainage-imbibition-hysteresis effect. The calculation of steady-state relative permeabilities, based on a pore-size distribution permeabilities, based on a pore-size distribution obtained from a Berea sandstone, is described. These relative permeability curves agree qualitatively with curves that are generally accepted to be typical for highly consolidated materials. In situations where interfacial effects predominate over viscous and gravitational effects, the following conclusions are reached.Relative permeability at a given saturation is everywhere independent of flow rate.Relative permeability is independent of viscosity ratio everywhere except at very low values of wetting phase relative permeability.Irreducible wetting-phase saturation following steady-state drainage decreases with increasing ratio of nonwetting- to wetting-phase viscosity.Irreducible wetting-phase saturation following unsteady-state drainage is lower than for steady-state drainage.Irreducible nonwetting-phase saturation following imbibition is independent of viscosity ratio, whether or not the imbibition is carried out under steady- or unsteady-state conditions. Experiments qualitatively verify the conclusions regarding unsteady-state residual wetting-phase saturation. Implications of these conclusions are discussed. Introduction Natural and artificial porous materials are generally composed of matrix substance brought together in a more or less random manner. This leads to the creation of a network of interconnected pore spaces of highly irregular shape. Since the pore spaces of highly irregular shape. Since the geometry of such a network is impossible to describe, we can never obtain a complete description of its flow behavior. We can, however, abstract those properties of the porous medium pertinent to the type of flow under consideration, and thus obtain an adequate description of that flow. Thus, the Kozeny-Carmen equation, by considering a porous medium as a bundle of noninterconnecting capillary tubes, provides an adequate description of single-phase provides an adequate description of single-phase flow. With the addition of a saturation-dependent tortuosity parameter in two-phase flow to account for flow path elongation, the Kozeny-Carmen equation has been used to predict relative permeabilities for the displacement of a wetting permeabilities for the displacement of a wetting liquid by a gas. It has long been recognized that relative permeability depends not only on saturation but permeability depends not only on saturation but also on saturation history as well. Naar and Henderson described a mathematical model in which differences between drainage and imbibition behavior are explained in terms of a bypassing mechanism by which oil is trapped during imbibition. Fatt proposed a model for a porous medium that consisted of regular networks of cylindrical tubes of randomly distributed radii. From this he calculated the drainage relative permeability curves. Moore and Slobod, Rose and Witherspoon, and Rose and Cleary each considered flow in a pore doublet (a parallel arrangement of a small and pore doublet (a parallel arrangement of a small and large diameter cylindrical capillary tube). They concluded that, because of the different rates of flow in each tube, trapping would occur in one of the tubes; the extent of which would depend upon viscosity ratio and capillary pressure. SPEJ p. 221

Summary We present visual cell and coreflood data pertaining to the influence ofwater saturation on miscible gasflood residual oil (water blocking). In visualcell studies, we equilibrate miscible gases and oils at reservoir conditionswith an intervening water phase. We find that the solvent-induced deposition ofseparated phase. We find that the solvent-induced deposition of separatedsolids causes initially water-wet quartz surfaces to become oil-wet. A numberof miscible coreflood displacements at high water saturation are considered, and the extent of water blocking is determined for Berea sandstone andreservoir cores. Displacements of fluid systems with wettability alteration andthose of refined oil systems without wettability alteration are reported. Wefind that water-blocking measurements with pure hydrocarbons overestimatemiscible flood Sor regardless of the porous medium (Berea or reservoirsandstone or a reservoir porous medium (Berea or reservoir sandstone or areservoir carbonate) and the flood (CO2 or hydrocarbon miscible). We furtherfind that water blocking is significantly more severe in Berea sandstone thanin reservoir rock. We assert that water-blocking measurements with refined oilsystems in Berea sandstone greatly overestimate water blocking in reservoirs, partially because refined oils cannot reproduce miscible-flood-inducedwettability alteration. Introduction The large viscosity contrast between injected miscible gas and inplacereservoir fluids leads to unstable displacements. The simplest method ofcontrolling this poor mobility ratio is to inject the miscible gas alternatelywith water - i.e., water-alternating-gas (WAG) injection. The WAG processimproves the volumetric sweep efficiency of the miscible flood but results in awater saturation that is high and mobile. Literature data show that, inwater-wet porous media, a high water saturation decreases the efficiency of amiscible flood by shielding remaining oil from injected solvent, a phenomenonsometimes called water blocking. Data also show that, in an oil- or mixed-wetmedium essentially all oil is accessible to the flood, even at very high watersaturations. The wettability of a porous medium could be altered during amiscible flood. Wettability alteration has been implicated as a contributor toa low residual oil for a high WAG flood in an originally water-wet porousmedium. When crude oils are mixed with solvents, suspended asphaltenes can bedestabilized. These highly polar molecules are surface-active and could adhereto the pore walls of a porous medium and change its wettability. pore walls ofa porous medium and change its wettability. For this study, we look at whathappens if a miscible flood causes the wettability to change from water- tooil-wet, focusing on (1) the effect that high water saturation has on themiscible flood recovery, (2) the extent to which water blocking is diminished, and (3) whether the initial or final wettability determines the extent of waterblocking. Our goal is to determine how severe water blocking affects oilrecovery in the field. Experimental Approach Our approach to the water-blocking problem is experimental. We used acapillary tube visual cell (CTVC) to study pore-level fluid contacts atreservoir conditions. Our objectives were to observe oil swelling and tomonitor the oil/water contact (OWC) angle. For some of the fluid systemsstudied in the CTVC, we performed coreflood displacements, again at reservoirconditions. In addition, we measured the extent of water blocking in reservoircores during refined oil displacements. Visual Cell Studies. The CTVC is a simple model of the pore-level contactsthat occur between injected gas and waterflood residual oil in water-wet porousmedia. In a water-wet medium, waterflood residual oil exists as isolated dropscompletely surrounded by water. Injected solvent does not contact oil directlybut initially is separated from the oil by a water film. Diffusion of solventthrough the water film is the only route of oil/solvent contact. In the CTVC, we experimentally reproduce this water-mediated oil/solvent contact in aquartz, thick-walled capillary tube (0.7 to 1.5 mm ID) (Fig. 1). We introduce abubble of solvent into the brine-filled tube and then inject oil into the tubeto obtain an oil droplet 1 cm from the near end of the solvent bubble. Thesephases are held at test pressure and reservoir temperature for a period rangingfrom 3 days to 1 month. We studied live and stock-tank oils and contacted oilwith both CO2 and propane. During a test, we monitor oil-phase volume, solidformation, and oil/water wettability. We determine phase volume by measuringphase length because the tube diameter is constant. The system is phase lengthbecause the tube diameter is constant. The system is valved so that we can movethe droplets carefully back and forth within the tube. We use these motions todetermine whether any material is adhering to the quartz tube and to monitorthe wettability of the tube where the oil has contacted it. Wettability ischaracterized with a contact angle measurement. The meniscus shape, however, isdistorted by the tube, which acts as a cylindrical lens. The distortion isparticularly severe away from the tube axis and interferes with directobservation of the contact angle. To measure the contact angle, we use thegeometrical relationship between the meniscus height, the tube radius, and thecontact angle, assuming that the meniscus is a spherical cap (Fig. 2). Then, the contact angle, c, is determined by measuring the meniscus height, h, and byuse of the following equation: (1) Because the interfaces can be moved with great control, both receding andadvancing contact angle measurements can be made. All contact angles reportedwere measured through the water phase, so angles less than 90 degrees arewater-wet and angles phase, so angles less than 90 degrees are water-wet andangles greater than 90 degrees are oil-wet. In addition to measurements of thecontact angle, qualitative wettability data are determined easily from themeniscus curvature. Displacement Experiments. To enable us to understand the effect ofwettability alteration on laboratory and field displacements, we performedseveral coreflood displacements. We used composite cores and reservoir fluidsto perform miscible WAG floods at a range of WAG ratios. To improve confidencein our understanding of the effect of wettability alteration on displacementefficiency, we also performed displacements with refined oils. Refined oilscannot alter wettability as substantially as crude oils because they lack thehigh-molecular-weight polar species principally responsible for surfaceactivity. The refined oil displacements are steady-state measurements where wedetermine the saturation of oil trapped by a WAG flood with afirst-contact-miscible solvent. We use n-tridecane (n-C13) as the oil to bedisplaced and n-tetradecane (n-C14) as the solvent. SPEFE P. 167

Feasibility of steam injection for three light-oil reservoirs in different geologic settings has been evaluated. The settings studied were a waterflooded deltaic sandstone, a waterflooded vuggy dolomite, and a deltaic sandstone structural trap with a gas cap. Optimization of steam injection to take advantage of individual reservoir characteristics is demonstrated.Results show that light-oil steamfloods can be designed to take advantage of post-secondary oil-saturation distribution. The resulting project may be carried out in a considerably different fashion from that of conventional heavy-oil steamfloods.We also re-evaluated an unsuccessful light-oil steamflood (LOSF) project carried out in the past. The re-evaluation correctly predicted failure because of early steam breakthrough. The results show that by considering details of geology and displacement process physics, the recent advances in reservoir characterization and modeling tools enable us to predict the performance of these projects more accurately.