Abstract
During the early development stages of the Middle Marg Tex oil zone in the Sunshine field, a rapid pressure decline was experienced. To forecast the future pressure behavior of the reservoir, unsteady-state calculations using the method developed in 1949 by van Everdingen and Hurs't were employed. This article reviews the calculation method and its limitations--particularly before some performance data are available. Illustrated is the variation of the calculated water influx constant (required for the unsteady-state calculations) at various times in the life of the reservoir. These data give an indication of the amount of performance history required to make a good pressure prediction. Also, the effect of higher and lower rates of production is shown. All calculated pressures are compared with the actual measured pressure performance.
Introduction
The undersaturated Middle Marg Tex oil reservoir in the Sunshine field, about 10 miles south of Baton Rouge in Iberville Parish, La., went on production in April, 1949. The reservoir was developed in 1949 and 1950. Reservoir pressure in Sept., 1950, had declined to about 4,300 psi from an original 4,750 psi. Less than 1/2 million bbl of oil had been produced of the estimated 9 to 10 million bbl of oil in place. Although it was obvious that the reservoir had a water drive, it was important to the operation of the field to predict the pressure behavior under anticipated future rates of withdrawal. The steady-state flow equation developed by van Everdingen and Hurst was employed in combination with the material balance equation to predict future pressures using performance data available after 525 days. This was a desk calculator prediction at the time and proved to be reasonably accurate. A computer program was developed for the pressure predictions allowing an examination of the sensitivity of various factors, critical assumptions and possible sources of error in the method used. It was found that very reliable predictions could be made after a relatively short period of production history. Also attempted was a prediction using only original geological and laboratory fluid analysis data. This approach required accurate determination of too many critical factors to be useful. In a reservoir acting under infinite boundary conditions, as the Marg Tex appears to be, the most critical factor is rate prediction. A reliable production forecast is required to predict pressure and water influx. The unsteady-state material balance calculations described can be a valuable tool to determine the effect of various rates on pressure behavior. The possibility of the reservoir being of limited size always must be considered. A finite reservoir introduces much additional uncertainty in the calculations, and comments on a finite reservoir are included in this article.
Geologic and Reservoir Characteristics
Situated on the flood plain along the north bank of the Mississippi River, the discovery well of the Sunshine field was drilled in late 1948 with a completion in the Upper Marginulina Texana zone at 10,310 ft. The Marginulina Texana zone is in the lower portion of the Upper Frio and varies in thickness from 750 to 900 ft. The productive sandstone unit is in the top 50 to 60 ft of the zone, and the remaining portion is composed mostly of massive compact shale. Due to its lenticular nature, the Marg Tex sand further divides into several reservoirs within the field. The Middle Marg Tex reservoir is the most widespread of the productive sands and appears to have extensive development to the east. The entire Marg Tex sandstone unit has good development in the Burtville field 4 miles to the northeast. The Middle Marg Tex has permeability barriers to the southwest due to an increase in limy material. Also, the zone appears to become shaly in the southeast portion of the field. The sands are firm, fine to medium grained and often slightly glauconitic. The porosity averages 29 percent and the permeability slightly over 1 darcy. Connate water is estimated at 23 percent and the gravity is 27.5 degs API. The formation volume factor is 1.1707 at the original reservoir pressure of 4,750 psig. Gas in solution is 400 cu ft/bbl and saturation pressure is 2,465 psig-2,285 psi below original pressure of 4,750 psig. The crude viscosity is about 3.23 cp at a reservoir temperature of 199F.
JPT
P. 595ˆ
