Thirty Years of Effective Pressure Maintenance By Gas Injection in the Hilbig Field
Authors: Kelly Philip , Kennedy S.L. 
Published: December 2007

Pressure maintenance, gas injection operations was initiated in the Hilbig field, Bastrop County, Tex., in Oct. 1933, only eight months after the field was discovered. The Hilbig field produces from a porous serpentine plug, and the primary producing mechanism for this reservoir was dissolved gas drive. Ninety per cent of all produced gas has been returned to the reservoir and the project has been characterized by a high degree of gravity drainage and excellent performance. An estimated 75 per cent of the original oil in place will be recovered as a result of this program, as compared to a 51 per cent recovery under the primary drive mechanism.

Introduction

The Hilbig field, which is located in southwestern Bastrop County, Tex., was discovered on Feb. 15, 1933, with the drilling of Humble's Annie Hasler 1 (now Hilbig Oil Unit 13). This well was completed from 2,006 to 2,115 ft subsea and produced at a rate of 1,700 STB/D on initial test. The Hilbig field produces from a porous supentine plug. The serpentine (Mg(OH)SiO-HO) is dull to dark green in color, fragmented, containing varying quantities of calcareous material as part of the matrix. From Feb. to April, 1933, eight more wells were drilled, four of which were dry holes and four were oil wells. By Sept., 1933, Humble had drilled eight additional oil wells and one dry hole. There are currently 13 completions in the reservoir-one injection well and 12 oil wells. All wells in the Hilbig field were competed in open hole with 7-in. casing set to within 7 ft of the top of the serpentine plug. The standard practice was to core below the production casing with a 6 1/8-in. core assembly until sufficient porosity had been penetrated to obtain satisfactory production.

Reservoir Properties

Fig. 1 is s structure map of the Hilbig serpentine reservoir. The crest of the plug lies at about 1,875 ft subsea while the estimated water-oil contact is at 2,185 ft subsea. The productive area of this reservoir covers about 300 acres. The base of the serpentine lies at depths varying from 2,205 to 2,432 ft subsea. The serpentine was extruded by a volcanic process and it is believed that the porosity was created by the expansion of escaping gases. Porosity from core data ranges from 0 to 37 per cent and averages 24.1 per cent. Permeabilities range up to 570 md. Cores from wells located in the central portion of the reservoir were analyzed, but core analysis data are not available for wells drilled near the edge of the reservoir.

Core descriptions and unsuccessful completion attempts indicate a dense serpentine of low porosity around the edges of the plug. Core analysis data are, therefore, not necessarily representative of the average rock properties throughout the reservoir. There are 45,746 acre-ft of serpentine present in this reservoir above the water-oil contact. Volumetric balance calculations indicate an original oil in place of 13,128,400 reservoir bbl. With an estimated average connate water saturation of 20 per cent, an average porosity of 4.6 per cent would be required to contain this amount of oil within the serpentine volume mentioned above. There is good pressure continuity between wells in spite of disproportionate withdrawals from the producing wells, and it is believed that all of the reservoir has been subject to drainage and that the average effective porosity is 4.6 per cent. Table 1 outlines pertinent data for this reservoir.

JPT

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