Applying the Frontal Advance Equation to Vertical Segregation Reservoirs
Authors: Joslin W.J. 
Published: December 2007

Abstract
The frontal-advance equation can determine how the fluid withdrawal rate and subsurface operating pressure influence oil recovery from pressure-maintained reservoirs having characteristics favorable for efficient vertical segregation. For effective vertical segregation in formations having low dip angles, the requirements are: thick, massive sands, low viscosity oil and high vertical permeability with few discontinuous shale members. This approach has been successfully applied to the LL-370, which is a massive Eocene sandstone reservoir containing crude with an average gravity of 260 API, a dip of only 30 and vertical permeability of 1/2 darcy. The average gas cap saturation was calculated for various rates of vertical gas-oil contact movement corresponding to a wide range of reservoir producing rates. This method also evaluated the effect of different pressure maintenance levels on oil recovery. Applicability of this procedure for calculating the present oil saturation in the LL-370 gas cap has been substantiated from field performance, where the oil saturation was computed by comparing oil recovery with the gas cap volume vacated.

Introduction
During the natural depletion history of the LL-370 reservoir, located in Lake Maracaibo, Venezuela, excellent vertical segregation resulted in the formation of a thin gas zone over a substantial portion of the oil-productive area. Subsequently, gas injection forced this thin gas-saturated zone slowly downward, reducing the oil saturation in the gas cap to a low value. The oil recovery has been raised considerably above earlier predictions where vertical segregation effects were under-estimated. In order to determine the maximum efficient producing rate and optimum operating pressure for this reservoir, a vertical gas frontal-advance analysis has been made through application of the fractional flow equation.

LL-370 RESERVOIR CHARACTERISTICS
The reservoir consists of a truncated monocline of massive, highly-permeable Eocene sandstone, called the B-6 formation, covering an area of more than 13,500 acres. The original oil in place was 2.17 billion STB. Internal non-sealing faults subdivide the structure into four blocks called the B-6-x.6, 10, 11 and 13, which are effectively bounded by major faulting on the flanks, an unconformity updip to the west, and an immobile aquifer to the southeast. The producing formation occurs at an average depth of 5,250 ft subsea and has a closure of more than 1,500 ft. A typical producing section has a net oil sand thickness of 170 ft. Scattered throughout the section are a few randomly-positioned shale lenses which increase in thickness and areal extent downdip. The reservoir rock and fluid properties vary with depth. The permeability and produced oil gravity are 1600 md and 280 API at the top, compared to 300 md and 18 API at the water-oil contact. The productivity of updip wells is, therefore, much higher than the reservoir average. The reservoir oil was originally saturated at the crest, grading to a slight degree of undersaturation at the water-oil contact. There was no original gas cap; and material balance and the field performance indicate no water influx. Except for the northern B-6-x.6 block, the fluid and rock properties have already been published. Average LL-370 reservoir properties are shown in Table l.

RESERVOIR PERFORMANCE UNDER NATURAL DEPLETION
Fig. 1 shows production performance from 1939 to date.
TABLE 1-LL-370 RESERVOIR PROPERTIES
Permeability (air) from cores, horizontal 975 mdPorosity 20.4 per centGravity 26.1 APIFormation volume factor, original 1.278Connate water saturation 12.4 per centSolution GOR, original 492 cu ft/bblOil viscosity, original 1.8 cpFormation dip 3Original pressure (-5250 ft subsea) 2490 psicSection thickness 198 ftNet oil sand thickness 148 ft
JPT
P. 87ˆ