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

Raimondi, P., SPE-AIME, Gulf Research and Development Co. Gallagher, B.J., SPE-AIME, Gulf Energy and Minerals Co.-U.S. Ehrlich, R., SPE-AIME, Gulf Research and Development Co. Messmer, J.H., SPE-AIME, Gulf Research and Development Co. Bennett, G.S., SPE-AIME, Gulf Research and Development Co. A field trial of caustic waterflooding in a Queen sand lens in the North Ward-Estes field is described. Comparison of results with projections for a conventional waterflood, while uncertain, indicate that about 25 percent more oil was produced. Operational problems are discussed. Introduction The North Ward-Estes field, Ward and Winkler Counties, Tex., has been under successful water drive for many years. However, a considerable amount of oil is left behind even in the water-swept zones. Laboratory tests have indicated that the oil displacement efficiency could be improved significantly by adding a high-concentration slug of sodium hydroxide (NaOH or caustic) to the flood water. In the swept zone, the laboratory-measured improvement was about 125 bbl/acre-ft. This is attributed to generation of surfactants by the reaction of caustic with organic acids in the oil and the effect of these surfactants on multiphase flow, primarily a wettability shift in the water-wet direction. These mechanisms have been discussed in other papers. The field test is being conducted in the Queen sand, East Flat area of the North Ward-Estes field. This area was discovered in 1969 and development drilling was completed during 1970 with the drilling of 20 additional wells. The oil production rate peaked at 85,000 bbl/ month during mid-1970, followed by a rapid decline in rate resulting from the highly undersaturated nature of the oil. To offset this decline, full-scale water injection was begun in late 1970. Production response to water injection was almost immediate and a peak rate of 40,000 bbl/month was reached in early 1971. To test the laboratory results, a 5-acre inverted fivespot pattern was developed by drilling four water-injection wells, WI-79 through WI-82. around an existing producing well, Well 874 (Figs. 1 and 2) in an area of the field that was presumed to have not yet been affected by the ongoing waterflood. The objective was to determine the effect of a caustic slug injected early in the life of a waterflood. This paper describes the test area, the laboratory evaluation, the design and conduct of the test, the production behavior and an analysis of the recovery. The production behavior and an analysis of the recovery. The test was still in progress when this paper was written. Reservoir Description Geologically, the Queen sand is a channel-type deposit. These deposits exhibit strongly directional permeabilities, generally northwest-southeast. Normal to permeabilities, generally northwest-southeast. Normal to this, the permeability is reduced to one-fourth or less of the dominant permeability. The East Flat Queen sand is rather fine-grained argillaceous, becoming increasingly anhydritic and dolomitic away from the central portion until reservoir development ceases to occur. Permeability and porosity pinchouts control the reservoir limits. However, northwest of Well 838 (Fig. 1) and along the southwest boundary, little geologic control is available and some water influx may have occurred. Fig. 3 shows a typical log section. The presence of gypsum and dolomite above and below the sand is evident from visual and other observations. X-ray diffraction analysis of producing sands gave 80 percent quartz and 10 percent feldspar as well as varying amounts of illite and montmorillonite clays. JPT P. 1359

To study mass transport in systems simulating oil recovery processes, different porous media were saturated with a mobile (carrier phase) and a stationary phase. Slugs of carrier phase containing a small amount of solute were displaced with pure carrier phase. By analogy to the chromatographic processes, the velocity of the solute can be predicted from a knowledge of the partition coefficient and the saturation provided that equilibrium between the two phases exists. Equilibrium was found to exist for different porous media, solutes and rates. The conditions were varied over the range normally encountered in the laboratory and in the field. The longitudinal dispersion of a solute undergoing interphase mass transfer was also investigated. Introduction The production of hydrocarbons by gas cycling, enriched gas drive and CO2 or alcohol displacement involves, among other factors, relative motion between two phases and compounds, hereafter called solute, which are soluble in both phases. The solute is carried forward by the faster flowing phase at a lower velocity than the average velocity of that phase. Retardation of the solute is caused by chromatographic absorption and desorption in the slower flowing phase and by the degree of departure from equilibrium. At equilibrium the concentration of solute in the two phases can be related by the equation* (1) where Csw and Cso are the concentration of solute in the aqueous and oleic phases respectively and K is the equilibrium ratio, or partition coefficient. Displacement theories must contain an explicit assumption with regard to equilibrium, i.e., whether the compositions can be related by Eq. 1. The existance of equilibrium depends, in general on the relative velocity between the phases. Unfortunately, other factors such as gravity segregation and viscous fingering, also depend on velocity. For this reason, whenever effects of rate on displacement were observed, it was practically impossible to discern what caused them - lack of equilibrium or the factors mentioned above. Equilibrium between phases has been the subject of extensive studies in fields such as extraction or chromatography. It has received only small attention in flow through the type of porous media encountered in oil production. For this reason a method was developed which makes it possible to study the movement of a solute as it is affected by rate, type of porous media, partition coefficient and carrier phase, but in the absence of segregation or fingering. The information obtained enables one to determine when the assumption of equilibrium can be made. Briefly, the method consists of (1) saturating the core with a mobile and an immobile phase, (2) injecting a slug made up of the same fluid as the mobile phase and a small concentration of mutually soluble solute, (3) measuring the lag and the peak height of the slug at arrival and (4) correlating these variables with fluid properties such as partition coefficient and mixing constants of the medium. PROPOSED MECHANISM The principles of chromatography are combined with the equation of longitudinal mixing to predict the velocity of a solute slug compared to the bulk velocity and the peak height of a slug. The equation so obtained is valid under equilibrium conditions only. Therefore, a comparison between experimental and predicted results will give a measure of departure from equilibrium. This work was done with either the oleic or the aqueous phase being immobile. For simplicity, the following development is based on the case where the oleic phase is immobile. However, the treatment is the same in either case. SPEC P. 51ˆ

A field test of forward combustion in a coal seam is described. The coal was retorted using techniques similar to those developed for conventional oil reservoirs. Relatively high heat-content coal oil and gas were produced. The burned seam was later exposed by strip mining, enabling produced. The burned seam was later exposed by strip mining, enabling visual observation and sampling of the affected coal. Introduction The objective of gasification of coal in place is the recovery of energy and chemicals without mining. The idea is more than 100 years old. Experiments began in Russia around 1931 and by the late 1940's field tests were started in several other countries. In the late 1950's only Russia remained active in this field and it began operation of large-scale plants. One of these plants produced 10 MMcf/D and plants. One of these plants produced 10 MMcf/D and another produced 45 MMcf/D of gas with heat content of about 85 Btu/cu ft. A third plant produced 10 MMcf/D with a heating value of about 120 Btu/cu ft. The gas was used to generate electricity. The cost of the produced gas, in terms of heat content, was about twice that of mined coal in the same region. Improved plants that would have produced gas at a lower cost per Btu than mined coal were designed to be put into operation in the 1960's. However, implementation of these may have been dropped because of the discovery of huge gas reservoirs in Russia. Experimentation on underground combustion of coal was resumed in 1972 by the USBM near Hanna, Wyo., where combustion is being carried out in a 30-ft thick seam. A complete history and useful lists of publications can be found in Ref. 1, and in a more publications can be found in Ref. 1, and in a more recent review of underground gasification of coal. At Gulf Research and Development Co., the study of processing coal in place began with an experimental laboratory program conducted in the early 1960's, and in 1968-69 a test of underground combustion of coal was carried out in a coal seam that was undergoing strip mining. Description and Results of the Tests What follows is a brief description of each phase of the test. A comparison of results of tests done by others is also presented. Location of the Test Site and Wells The project was carried out in No. 14 coal, a typical bituminous coal in Western Kentucky, at a depth of 107 ft. In this area coal seam was about 9-ft thick. See Table 1 for coal analysis. The project consisted of two test patterns that were drilled 100 ft apart. Each pattern contained an injection well, a temperature observation well, and a sampling well in a row perpendicular to the strip mining wall (see Fig. 1). Temperature observation wells were 10 ft and sampling wells were 30 ft from the injectors. The injectors were furthest away from the strip mining wall, approximately 500 ft. They were designated Wells I-1, T-1, and S-1 for the injection, temperature observation, and sampling wells, respectively, for the first pattern, and Wells I-2, T-2, and S-2 for the corresponding wells in the second pattern. pattern. JPT P. 35