A Successful Cyclic Steam Injection Project in the Santa Barbara Field, Eastern Venezuela
Authors: Bowman C.H. , Gilbert S. 
Published: December 2007

The Santa Barbara project is a success. It is significant that cyclic steam injection can result in the production of secondary oil; significant, too, is the fact that in less than three years primary reserves are being recovered that would have required primary reserves are being recovered that would have required twelve years to produce without steam.

Introduction

Santa Barbara is a large, geologically complex field in Monagas State, Northeast Venezuela (Fig. 1). The Sacacual sands, oil-bearing along the field's northern edge, constitute Santa Barbara's shallowest reservoir. The Mene Grande Oil Co.'s portion contains some 70 million bbl of 16 degrees to 19 degrees API naphthenic-base crude oil, ranging in viscosity from 120 to 510 cp. Average reservoir temperature is 85 degrees F.

The Venezuelan Atlantic Refining Co. drilled the discovery well, Pirital-6, in early 1958. Mene Grande's initial well was BG-123, completed in May, 1958. Through 1964, 22 wells had penetrated Mene Grande's portion of the reservoir.

Geologists have identified 15 discrete lenses within the Sacacual group. From a reservoir engineering standpoint, however, there are only two separate reservoirs. Five upper lenses (S-15 through S-19) contain 16 degrees API oil, and three lower lenses (S-22 through S-24) contain 19 degrees API oil. Figs. 2 and 3 are net sand isopachous maps of these "upper" and "lower" zones. Wells completed in a particular zone are circled. Production is not commingled. Production is not commingled. The reservoir trap is a south to north overlap of the unconsolidated Sacacual lenses on a northward-rising Carapita unconformity surface. Dips average 20 degrees to 25 degrees. As the Fig. 4 cross-section shows, separation of the upper and lower reservoirs is supported not only by differences in crude oil properties, but also by a substantially lower oil-water contact in the lower zone. Owing to the steep dip and thick sands, the span of productive depths extends from 200 to 1,150 ft below the ground surface.

Fig. 5 illustrates normal completion practice, which is to set casing through the deepest potentially productive interval, perforate the desired lenses, and gravelpack a slotted inside liner into place for sand control. Slotted sections as long as 390 ft have been gravel-packed without difficulty.

Primary production appears to result almost entirely from gravity drainage. The low original reservoir pressure essentially equal to the fluid gradient of pressure essentially equal to the fluid gradient of 0.34 psi/ft renders negligible any fluid expansion effects. Production rates declining with time suggest the lack of an effective water drive. Water has now broken through into most of the downdip wells, although it is doubtful that efficient displacement of very much oil has resulted. We suspect that the water simply fingers updip toward the pressure sinks created by the pumped-off wells.

Primary production history of the over-all reservoir is graphed in Fig. 6. The observed production decline fits quite well an exponential (constant percentage) decline curve. By extrapolation, an ultimate recovery of 5.54 minion bbl of oil, or 6.9 percent of the oil in place, is forecast at abandonment. No additional place, is forecast at abandonment. No additional development wells were planned.

Performance of each of the zones, the upper and the lower, is presented in Fig. 7.

JPT

P. 1531