Laboratory and field techniques for measuring oil saturation were applied to an oil-wet reservoir. Log-inject-log and core measurements confirmed a 3.1 saturation exponent. Ultimate residual oil saturations determined by log-inject-log, core analysis, and microlaterolog procedures using laboratory-determined cementation and saturation exponents were in good agreement. Introduction In evaluating the prospects for commercial application of enhanced recovery processes, one of the most important factors to be considered is the quantity and distribution of oil present in the pore space at the time the process is to be applied. Waterflooding tends to leave low oil saturations in high-permeability zones and high saturations in tighter zones. Where expensive processes are to be applied, it is vital that the oil saturation distribution be established as accurately as possible. We have avoided the term "residual oil" because it is not precisely defined in the literature. Instead, the term "ultimate residual" is used to describe thoroughly flushed sand near the end-point of the relative permeability curve, and "current oil saturation" refers to the oil permeability curve, and "current oil saturation" refers to the oil saturation at some defined point in the production history of a reservoir. It is difficult to determine the oil saturation in a waterflooded reservoir for tertiary recovery purposes because there is some mobile oil present and significant changes can occur during drilling or coring. During the past few years, the rapid expansion of field testing of past few years, the rapid expansion of field testing of tertiary recovery processes using expensive chemical fluids has accentuated the importance of upgrading the accuracy of determination of oil saturation after secondary recovery. The industry has responded with several useful techniques, including special coring, logging, and tracer procedures. A number of excellent papers have been published giving details of these methods. This paper reports on the application of several techniques to a paper reports on the application of several techniques to a strongly oil-wet reservoir - the North Burbank Unit Tract 97 area. Nature of the Reservoir The North Burbank reservoir, which lies at a depth of about 3,000 ft, is a relatively clean, well consolidated sandstone of a type that occurs in many fields of north-eastern Oklahoma. The sand averages 47.2-ft net thickness, 16.8-percent porosity, and 50-md permeability. The stock-tank oil has a gravity of 39 degrees API. Tract 97, where the tertiary pilot is being run, is one of the most homogeneous areas of the North Burbank field. There are frequent, thin, shale laminae, but these do not interfere markedly with vertical fluid movement. Dispersed shales occur occasionally in the sand column, but water-sensitive clays have not been observed in the North Burbank reservoir. It long has been known that the North Burbank reservoir is strongly oil-wet. During the development of the waterflood, at least two wells on each quarter section were cored and, at frequent intervals, a wettability index designated as the Amott-Harvey "relative displacement index" has been run. This technique, which is similar to the Amott wettability measurement, compares the tendency of a permeability plug at irreducible oil to imbibe oil with the tendency of the same plug at irreducible water to imbibe water. The results are expressed as numbers ranging from − 1.0 (oil-wet) to + 1.0 (water-wet). Details of the procedure are given in Ref. 8. There is always some variation from specimen to specimen within a well, and from well to well, but the average over the North Burbank Unit is -0.7, strongly oil-wet. JPT P. 491

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Substantial areas of the North Burbank Unit, Osage County, Oklahoma, gave poorer than average response to waterflooding. After studies showed that the performance of these areas could be traced to greater than field average heterogeneity, a pilot polymerflood was conducted during the period from 1970-1979. Good response to polymerflooding, followed by economic evaluation of proposed expanded operations, led to the design and implementation of a 1440 acre commercial scale project. The project involved injection of fresh water preflush during the period from September, 1980 to late April, 1981. Then a liquid emulsion type polyacrylamide was blended to 500 ppm in fresh water and injected at a total rate of 63,000 BPD until approximately 4.4 percent of the pore volume had been injected. This was followed by a water spacer, and a 0.8 percent (PV) slug of aluminum citrate containing 500 ppm of aluminum was injected as a cross-linking agent into those two-thirds of the injectors which were expected to present no injectivity problems. Following injection of a second water spacer, 500 ppm polymer injection was resumed. Plans call for injection of polymer at 500 ppm until the total amount reaches 15 percent of pore volume. This will be followed by polymer slugs of 250 ppm (10 percent of pore volume) and 50 ppm (15 percent of pore volume), fresh water (20 percent of pore volume), and finally drive (produced) water. Any localized channeling problems will be handled by treating individual injection wells with crosslinking agents such as aluminum citrate. Methods of scaling up pilot results to the 1440- acre commercial project, site selection, design of the fresh water preflush, estimation of aluminum citrate requirements, and project costs are discussed.

Trantham, J.C., SPE-AIME, Phillips Petroleum Co. Phillips Petroleum Co. Patterson Jr., H.L., SPE-AIME, Patterson Jr., H.L., SPE-AIME, Phillips Petroleum Co. Phillips Petroleum Co. Boneau, D.F., SPE-AIME, Phillips Petroleum Co. Phillips Petroleum Co. JULY 1978 Careful control of fluid rates, injection pressures, volumetric balance, and quality control of injected chemical solutions are key factors in chemical flooding in the fractured, oil-wet North Burbank Unit reservoir. Fluid diversion treatments based on radioactive tracer studies helped maintain reservoir control. After 18 months of operation, pilot performance is encouraging. performance is encouraging. Introduction Fresh-water preflush injection began in the North Burbank Unit surfactant/polymer pilot in Osage County, Okla., on Dec. 1, 1975. This was followed by a sequence of slugs, including controlled salinity preflush, surfactant solution, and a graded viscosity-mobility buffer that is now about 60 percent complete. A description of the oil recovery process was presented in an earlier paper. This study reports the field operations involved when mixing and injecting the fluids, control of fluid composition, efforts to optimize the movement of fluids within the reservoir, and techniques used when analyzing the progress of the pilot's different phases for the past 19 months. Pilot Layout and Equipment Pilot Layout and Equipment Pilot Pattern and Water Supply Pilot Pattern and Water Supply The pattern (Fig. 1) was composed of an array of nine inverted five-spots of approximately 10 acres each (5 acres/well). Injection wells were fed by two gas-driven, triplex pumps located at the flow station adjacent to the chemical blending building at the southwest corner of the tract. Fresh water used for preflushing and for preparing all chemical solutions was obtained from wells completed in the alluvium of the Arkansas River. The only required treatment of the supply water was the addition of a corrosion inhibitor at the water supply station. An oxygen scavenger also was added to assure that no oxygen was present to form iron-containing corrosion products that would plug the formation and interfere with the products that would plug the formation and interfere with the oil-displacing chemical processes. The water contained about 1,000 ppm total dissolved solids, including less than 100 ppm total hardness. This contrasted strongly with the 80,000-ppm (total solids) formation water that allowed fresh-water production to be used as a continuously injected tracer for supplementing the radioactive tracers. Equipment Fig. 2 shows a simplified flow diagram of the chemical blending system. Three basic assemblies make up this system: the brine maker, the surfactant blender, and the polymer mixing system. Air was excluded from all three polymer mixing system. Air was excluded from all three of the chemical mixing systems, using a nitrogen blanket. Brine Maker. A brine averaging 31-weight-percent sodium chloride was prepared continuously by percolating fresh water through a bed of salt crystals. percolating fresh water through a bed of salt crystals. This concentrated solution was blended to the desired concentration by a proportioning pump that injected it into the fresh water fed to the injection pumps or to the surfactant blender. The concentrated brine varied no more than +/- 1 weight percent in concentration. This system was used during the injection of saline preflush and surfactant blending. P. 1068

From 1955 to 1958 the Phillips Petroleum Co. conducted a series of small scale counterflow combustion field tests in a tar sand about 60-ft deep and 6 to 12-ft thick near Bellamy, Mo. A total of seven different well patterns, including conventional five-spots and seven spots plus a 15-well line drive pattern and a 10-well radial pattern, were employed. Electric heaters, gas burners and wellbore fuel packs were tested as counterflow ignition devices. Direct drive ignition followed by reversal to counterflow operation was not possible in this case because of formation plugging by the semi-solid tar during the direct drive phase. Sustained counterflow burning was achieved with wellbore fuel packs under controlled conditions which permitted close correlation of fire front velocity, air velocity, air-oil ratios and yields for a wide variation in process parameters. The tar in place was about 100 API with a reservoir viscosity greater than 500,000 cp. The composite oil product was 260 API with a viscosity in the range of 5 to 15 cp. Vertical sweep efficiency in the line drive pattern was essentially 100 per cent, with no evidence of gravity segregation. Original tar in place ranged between 800 and 1,000 bbl/acre-ft, specific rock permeability averaged about 800 md before burning and elective air permeability with residual oil and water in place (at the time of ignition) averaged 250 md. The volume of oil recovered during stabilized line drive counterflow burning represented about 67 per cent of the volume of tar originally in place in the burned out zones. A minimum was found when air-oil ratios were plotted against formation air velocities, and a limiting air velocity existed below which the counterflow fire front reversed and burned back over its own trajectory, using the residual coke left behind. Introduction Early in 1955 the Phillips Petroleum Co. began preparations to field test counterflow underground combustion as a method for producing oil from high viscosity hydrocarbon deposits, such as bituminous (tar) sands. At that time all published information on the use of underground burning to increase oil recovery was based on the direct drive process, in which the fire front moved through the formation in the same direction as the injected air stream. Such direct burning is not applicable to many heavy oil sands or to most tar sands because the heat-thinned native hydrocarbon congeals in the cold rock ahead of the fire front forming a gas permeability block which smothers the combustion. Laboratory experiments first demonstrated that this permeability blocking would not occur if the fire front and the air stream moved in opposite directions. In this counterflow (reverse) burning process the heated heavy oil or tar is driven back through the combustion zone. Here thermal cracking produces relatively light hydrocarbon products which pass through the heated rock behind the fire front (largely in the vapor phase) and are incapable of causing a gas permeability block. Exploratory coring revealed that consolidated bituminous sandstones with a combination of tar saturation, permeability, thickness and depth favorable for experimental field testing existed at several points in western Missouri. By the fall of 1955, a test site for determining technical feasibility of the counterflow process under field conditions had been selected near Bellamy, Vernon County, Mo. about fifty miles north of Joplin. The pay zone was too thin and too shallow to constitute a commercial prospect, but these same factors permitted controlled experimental operation with a small compressor installation and with a large number of monitor wells. These were needed for adequate observation of the underground phenomena at reasonable cost. RESERVOIR CHARACTERISTICS The reservoir chosen for the experimental field tests was a 12-ft thick section of tar sand extending from 49 to 61 ft subsurface, with shale and siltstone laminations sealing the top and bottom. This section was part of a larger 30-ft thick tar sand deposit which extended both above and below the test zone. Core analyses showed that the 12-ft sand was effectively subdivided into two approximately equal sections, with the lower zone being consistently more permeable than the upper zone. The most significant laboratory core data are summarized in Table 1. The line drive test which is the principal subject of this report utilized only the lower 6-ft thick zone, with the upper zone regarded as part of the 55-ft overburden. WELL PATTERNS The over-all field test program involved a total of seven different well patterns, including conventional five-spots and seven-spots plus a 15-well line drive pattern and a 10-well radial pattern. JPT P. 109ˆ