In order for the reservoir engineer to calculate the amount of hydrocarbon in place from geological information, the reservoir bulk volume must first be calculated. Many methods exist to estimate the reservoir bulk volume but only two will be discussed here.
The first method involves the reservoir engineer using well logs, core data, well test data, and two-dimensional seismic data to estimate the bulk volume.1,2 From this information, the engineer generates digital subsurface and isopach maps of the reservoir in question. These maps are then used in computer programs to estimate a volume for a given hydrocarbon, either gas or oil, in place.3
A subsurface contour map shows lines connecting points of equal elevations on the top of a marker bed and therefore shows geologic structure. A net isopach map shows lines connecting points of equal net formation thickness, and the individual lines connecting points of equal thickness are called isopach lines. The contour map is used in preparing the isopach maps when there is an oil-water, gas-water, or gas-oil contact. The contact line is the zero isopach line. The volume is obtained by planimetering the areas between the isopach lines of the entire reservoir or of the individual units under consideration. The principal problems in preparing a map of this type are the proper interpretation of net sand thickness from the well logs and the outlining of the productive area of the field as defined by the fluid contacts, faults, or permeability barriers on the subsurface contour map. When the formation is rather uniformly developed and there is good well control, the error in the net bulk reservoir volume should not exceed a few percentage points.The standard cubic feet of gas in a reservoir with a gas pore volume of Vg ft3 is simply Vg/Bg, where Bg is expressed in units of cubic feet per standard cubic foot. As the gas volume factor Bg changes with pressure (see Eq. [2.16]), the gas in place also changes as the pressure declines. The gas pore volume Vg may also be changing, owing to water influx into the reservoir. The gas pore volume is related to the bulk, or total, reservoir volume by the average porosity φ and the average connate water Sw. The bulk reservoir volume Vb is commonly expressed in acre-feet, and the standard cubic feet of gas in place, G, is given by
The areal extent of the Bell Field gas reservoir was 1500 acres. The average thickness was 40 ft, so the initial bulk volume was 60,000 ac-ft. Average porosity was 22%, and average connate water was 23%. Bg at the initial reservoir pressure of 3250 psia was calculated to be 0.00533 ft3/SCF. Therefore, the initial gas in place wasG = 43,560 × 60,000 × 0.22 × (1 – 0.23) ÷ 0.00533
= 83.1 MMM SCF
Because the gas volume factor is calculated using 14.7 psia and 60°F as standard conditions, the initial gas in place is also expressed at these conditions.
Because the formation volume factor is a function of the average reservoir pressure, another problem in any calculation of bulk hydrocarbon volume is that of obtaining the average reservoir pressure at any time after initial production. Figure 4.1 is a static reservoir pressure survey of the Jones sand in the Schuler Field.4 Because of the large reservoir pressure gradient from east to west, some averaging technique must be used to obtain an average reservoir pressure. This can be calculated as either an average well pressure, average areal pressure, or average volumetric pressure, as follows
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