Detailed descriptions are given of materials, apparatus and the experimental procedure used to study the effect of bacteria on sandstone permeability. The factors affecting permeability during injection of bacterial suspensions which have been investigated are:concentration of bacteria;core permeability and median pore size;species of bacteria, mode of aggregation and relative size;injection rate or pressure differential;mean pressure; anddepth of penetration of bacteria. The investigation demonstrated that bacteria cannot reduce core permeability to zero and that their effect on permeability is subject to definite limitations. Remedial or permeability restoration studies also were made. Acidization in combination with reverse flow was found to be an effective method for restoring permeability in cores partially plugged with bacteria. The relationship between the bacterial quantities in the laboratory tests and those found in field operations is discussed. The linear laboratory flow data have been translated into terms of field radial systems; these data indicate the most practical methods of maintaining injection rates in the presence of bacteria are to increase injection pressures or hydraulically fracture the formation. Introduction It has long been known that various bacteria flourish in the above-ground components of oil field water- injection systems. The presence of these bacteria has led to the suspicion that they might enter into the causes for reduction of injection well permeability, but only recently has an attempt been made to describe the effects quantitatively. Biocides are used in many cases without a firm knowledge as to whether the bacteria are killed, or if they are, whether the dead cells affect formation permeability. This project was undertaken as part of a study to determine the effect of bacteria, residual oil and precipitated solids such as iron sulfide or calcium carbonate on the permeability of sandstones and to learn whether any of these materials adversely affect brine injectivity in secondary recovery or disposal operations. This report deals with that portion relating to the effect of bacteria. MATERIALS CORES Three different permeability ranges of Berea sandstone cores were used in the study. The range of initial, absolute brine permeabilities ki were: high - 278 to 400 md; medium-130 to 162 md; and low-17.7 to 48.3 md. The permeability data for the cores used in the tests are included in Table 1. All cores were cut to a nominal 1 in. diameter. Following air permeability determinations, they were molded with an epoxy resin in 1.5 in. ID aluminum sleeves. The sleeves had drilled and tapped holes for intermediate pressure connections along the length of the cores. After molding, the high- and medium-permeability cores were trimmed to 4 in. in length and the low-permeability cores to 2 in. These lengths resulted in pore volumes of approximately 10.9, 10.4 and 4.4 ml. respectively, for the high-, medium- and low-permeability cores. Pressure transmitting channels were drilled through the plastic into the core proper, using the sleeve holes as drill guides. Width and depth of channel penetration into the core proper were approximately 0.03 in. and 0.05 in., respectively. Three pressure taps were used with all cores; for the high- and medium-permeability cores the taps were spaced 1 in. apart; for the low-permeability cores the taps were spaced 0.4, 0.8 and 1.2 in. from the inlet end. Pore size distributions were calculated from restored- state capillary pressure curves for representative cores in each of the three permeability ranges. In each case the pore size range with the greatest percentage of the pore space included the very small pores up to 0.5 micron in radius. The median pore radii were in the 5.5 to 6 micron range for the high-permeability cores; in the 4.5 to 5 micron range for the medium-permeability cores; and in the 3.5 to 4 micron range for the low-permeability cores. JPT P. 805^

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Introduction This paper presents the results of laboratory and field investigations of the differential separation processing of primary separator liquids to the stock tank. The process basically consists of removing dissolved gases from primary separator liquids by both flash and differential vaporization rather than by conventional flash separation methods. When the gases are so removed stock-tank recovery is increased, since the differential process affords the equivalent of an infinite number of flash separation stages. While the process is applicable to any primary separator liquid, the largest stock-tank recovery increases generally are obtained with rich liquids having a high propane-hexane content. The laboratory phase of the study was concerned primarily with devising a simple method for evaluating the relative merits of the flash and differential processes. Utilization of the method is shown in connection with three primary liquids of widely differing characteristics. Recovery by differential separation was from 4 to 7.5 per cent greater than that obtainable by optimum two-stage flash separation. In one case analyses were made of the tank oils obtained by both processes to determine the distribution of the recovery increase. The laboratory method developed was instrumental in the design of a prototype differential separator for field testing. It was found that a combination flash-differential separation process is essentially as efficient as complete differential separation. Consequently, design simplification of a field prototype was possible, and the diversion of high-pressure gas from sales for operation was unnecessary. The prototype separator used for field testing was constructed to permit either three-stage flash or flash- differential operation. The separator was tested on a condensate well stream. using the alternate methods until sufficient data were obtained for reliable evaluation. Stock-tank recovery increases by the differential process of some 5 per cent were obtained. Concurrent laboratory tests included stage and differential separations and relative weathering rate tests. The laboratory tests generally substantiated the field results, indicating that such tests can be used to evaluate the differential separation potential of a specific well stream. The Flash and Differential Processes The evolution of gas from complex hydrocarbon liquids during a pressure decline may occur by either a flash or differential process. In the flash process gas is evolved as a result of a pressure decline, and it remains in contact with the residual liquid. The composition of the system as a whole does not change in a flash process during the pressure decline. In a differential process gas evolves as a result of a pressure decline and is removed continually from the system. Removal of gas in this manner causes a change in the overall composition of the system. In a complete differential process the pressure decline. gas evolution and gas removal are continuous. The differential process is introduced first in field separation when gas or liquid is removed from the primary separator. In each subsequent stage of separation the liquid initially undergoes a flash vaporization to equilibrium gas and oil, followed by a differential process as actual separation occurs. JPT P. 998^