Operation and Performance of the Slocum Thermal Recovery Project
Authors: Hall A.L. , Bowman R.W. 
Published: December 2007

As a result of a steam-injection process that uses the underlying water layer, impressive quantities of oil have been recovered from a reservoir that previously yielded only marginal production. Although many difficulties have reduced the profitability, it is expected that by applying recent technology and field experience, the oil-steam ratio, and hence the economics, will be significantly improved.

Introduction and History
The Slocum field is in southern Anderson County in northeast Texas. Production of 19 degrees API oil, ranging in viscosity from 1,000 to 3,000 cp is from the shallow Carrizo formation (500 to 600 ft). The oil accumulation is anticlinal bounded on the north by a fault and elsewhere by the oil-water contact. (See Fig. 1.) Although the sand is generally very clean, and has a permeability of about 3,500 md, the viscosity of the oil at the reservoir temperature of 75 degrees F allows only marginal primary recovery. Since the discovery of the field in 1955, numerous exploitation attempts have recovered only 300,000 bbl of oil, or about 1 percent of the original oil in place. A typical primary well produces only 1 to 2 BOPD. primary well produces only 1 to 2 BOPD. The viscosity-temperature behavior of the oil is such that its viscosity is reduced by a factor of more than 100 when the temperature is increased to 350 degrees. (see Fig. 2), which suggests that the oil might be produced successfully with thermal recovery produced successfully with thermal recovery processes. Other favorable conditions for such a process processes. Other favorable conditions for such a process are the shallow depth of the accumulation, the high oil saturation (65 percent), and the availability of high-quality, fresh water for generating steam or hot water. However, the absence of natural reservoir energy eliminates the possibility of a steam soak, and the high viscosity of the oil precludes a direct steam drive in the oil column. Initial reservoir pressure is only 110 psig with no significant gas saturation. Preliminary field tests indicated that although these Preliminary field tests indicated that although these processes would recover additional oil, they would not processes would recover additional oil, they would not be economical. Thus, merely reducing oil viscosity in the reservoir is not sufficient. If the oil is to be successfully unlocked, a more efficient recovery process must be used. process must be used. The reservoir geometry provides the means for such a process. Throughout the field, a water sand underlies the oil sand. (See Fig. 3 for type log.) If steam were injected into this sand, heat would be introduced into the reservoir faster, and would be placed in contact with a much greater portion of the placed in contact with a much greater portion of the oil than by injection into the oil zone. To test this steam-injection process, a 1/4-acre pilot was conducted in 1964–1965. It consisted of a normal five-spot pattern with four injectors, a central producer, and a temperature observation well equipped producer, and a temperature observation well equipped with a thermocouple. Approximately 40 percent of the oil in place within the pilot area was produced. Encouraged by this favorable recovery, Shell Oil Co. started a full-scale 7-pattern project in 1966–1967. Designated as Phase 1, it consisted of 5.65-acre, 13-spot patterns elongated in a NE-SW direction. (See Fig. 4.) The elongation was expected to compensate for a NE-SW preferential flow that had been observed during primary and pilot operations. Both production and injection wells were completed a few production and injection wells were completed a few feet into the water sand.
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