The ability of commercial foaming agents to function at elevated temperatures and over extended periods of time has been determined in anticipation of periods of time has been determined in anticipation of their use in EOR applications. Preliminary screening is done in simple glass apparatus at the boiling point of water for a period of a week. About one-third of those tested do not foam at all at 100 degrees C, about one-third lose their foaming power during the week and the last third are still functioning at the end of the period. Some of the anionics are usually the best while the nonionics are generally the poorest. Injection of foamer solution into unconsolidated porous media at temperatures well above the boiling porous media at temperatures well above the boiling point of water will decrease the gas flow rate point of water will decrease the gas flow rate significantly more than will the injection of water alone. In time the gas flow rate will increase again, but injection of more foamer solution will cause it to decrease to even lower levels than the previous injection. Introduction Foaming agents and other surfactants have been proposed and in some cases tested and used in many proposed and in some cases tested and used in many oil field operations. Most of these applications require that the materials be effective over extended periods of time and some also require that they work periods of time and some also require that they work at elevated temperatures. The latter may range from reservoir temperatures up to the 500 degrees F or so encountered in steam injection applications. The proposed use of foam for leveling injection profiles proposed use of foam for leveling injection profiles in steam injection projects is an example of the latter which interests us. We know that many surfactants are biodegradable, which is an advantage in some applications, but not those extending over long periods of time. We also know that some surfactants contain chemical bonds which we would expect to be hydrolyzed when the surfactants are in aqueous solutions for a matter of a few days. Even though oxygen would have to be introduced from the surface of the ground, some surfactants may also be affected by it. Some of these decomposition mechanisms may be catalyzed by reservoir rock components such as clays and all are probably accelerated by modest increases of probably accelerated by modest increases of temperature. Changes in surfactants with time have been noted by others working in the field of EOR. Cash, et al. reported aging effects for petroleum solfonate, cosurfactant, and hydrocarbon systems which they felt were physical rather than chemical in nature. Viscous liquid crystalline phases were slowly formed, which would certainly have affected fluid flow. Clementz and Gerbacia found that petroleum sulfonates were deactivated by some components of crude oil and indicated that this could be significant in field tests or applications. The tacit assumption is generally made that since we can have aqueous foams at ambient temperatures and atmospheric pressure, we can also have them at elevated temperatures and pressures. Beyers et al. have reported that their bulk foam had measurable flow properties up to 180 degrees F and 860 psi. But to our knowledge no one has demonstrated directly that foam can be both generated and retain its form in porous media at the temperatures and pressures encountered in underground steam injections. This paper contains the results of two consecutive but independent studies. The first has to do with the measurement of the ability of many foaming agents to produce foam from their boiling solutions for periods of time up to one week. The second has to do with foam generation in unconsolidated porous media by the best agents found in the first study, first at 100 degrees C and then at higher temperatures. APPARATUS AND PROCEDURE

A two-part study was conducted to define optimal gravel-pack procedures for some high-angle well completions in an area operated by Chevron U.S.A. Inc. In the first part of the study, gravel slurries were pumped through a I,080-ft [329-m] tubing string to simulate actual slurry transport conditions in high-angle wells. The tubing string had an inclination of 80° [1.4 rad] from vertical. Measurements were made to determine suitable viscosity and solids concentration for effective gravel transport. In the second part of the study, a full-scale cased-hole completion model was constructed. Gravel slurries that had satisfactory transport performance were tested for packing characteristics in the model well bore (completion interval). The need for special completioninterval geometry to obtain satisfactory packs was investigated.Results showed that high-viscosity carrier fluids (600 to 700 cp [0.6 to 0.7 Pa's]) with high gravel concentrations (15 Ibm/gal [1797 g/ dm 3 ]) provide good transport, but they are unsuitable for use in completion intervals in wells with angles of 80° [1.4 rad] from vertical. Satisfactory transport and improved packing were achieved with lower carrier viscosity and concentration (300 to 400 cp, 4 Ibm/gal [0.3 to 0.4 Pa' s, 479 g/dm 3]). Special liner-tailpipe (washpipe) geometry considerations reported by previous investigators are required in conjunction with the optimal slurry properties defined in this study.Completion operations designed from results of this study have satisfactorily met general placement criteria. Field experience to date has been in wells with inclinations up to 80 ° [1.4 rad] from vertical.

~-Foam gravel packing experiments run in a fullscale model wellbore demonstrated that foam is a viable alternative to conventional carrier fluids such as water and viscous polymer solutions in select instances.Because of its special characteristics, foam may have over these fluids in completions where 1m" pressure or sensitive formations are encountered.

Flow of a two-phase, gas-liquid, fluid in a model wellbore has been studied.Observations using an air-water system are related to in-wellbore phase separation of two-phase steam typical of that being injected into multiple perforations or zones.The air-water system has a phase density difference similar to steam vapor and liquid.Results show that when such a two-phase fluid exits the inje"C'-tion tubing in the model wellbore, separation of the phases occurs.This may translate into nonuniform steam quality distribut10n at varlOus points in an interval undergoing steam injection. Phase separation in the wellbol"e is of conc€'t-n because it may affect steam drive or stimulation efficiency.Parameters that affect in-wellbore vapor-liquid distr'ib~tion include completion geometry, total injection flow rate, and downhole quality.

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