As mentioned earlier, the * Volumetric Method* for STOOIP uses estimates of static geologic data to determine the volumes of the in-place fluids (crude oil, natural gas, and water). Static data are data which do not change with time due to oil and gas production. These static data are measured from core and log data.

For the volumetric method, the * Gross Rock Volume* (total rock volume of the reservoir zone of interest) and average values of porosity, fluid saturation,

*ratio (ratio of the volume of the productive reservoir to the total rock volume, i.e., the ratio of the volume of the reservoir that contributes to flow to the total rock volume), and the fluid formation volume factors (${B}_{f}$ ). While these properties can be determined on a point-by-point basis from core and log data at the well locations, development geologists use specialized geological modeling techniques to determine the inter-well properties and the averaged values of these properties.*

**Net-to-Gross**By simply using the definition of reservoir volumes, the in-place volumes of the different reservoir fluids can be determined by:

Where:

- $V$ is the in-place volume of phase p, STB for crude oil and water or SCF for natural gas
- ${V}_{grv}$ is the gross rock volume, ft
^{3} - $\overline{{h}_{n}}/\overline{{h}_{g}}$ is the net-to-gross thickness ratio, fraction
- $\overline{{h}_{n}}$ is the average net reservoir thickness, ft
- $\overline{{h}_{g}}$ is the average gross reservoir thickness, ft

- $\overline{\varphi}$ is the average reservoir porosity, fraction
- $\overline{{S}_{p}}$ is the average phase saturation, fraction
- $C$ is a unit conversion constant, 5.615 ft
^{3}/bbl for crude oil and water or 1.0 for natural gas - $\overline{{B}_{p}}$ is the average formation volume factor of phase $p$ , bbl/STB for crude oil and water or ft
^{3}/SCF for natural gas

In **Equation 4.02**, $\overline{{h}_{n}}$ , is the average net thickness (the thickness of the reservoir that (1) contains hydrocarbons and (2) has sufficiently high permeability to contribute to flow), and $\overline{{h}_{g}}$ is the average gross thickness (the total thickness of the reservoir). The net-to-gross ratio is simply the fraction that converts the total reservoir thickness to the thickness that contributes to hydrocarbon storage and flow in the reservoir. We can further define the gross rock volume as:

Where:

- ${V}_{grv}$ is the gross rock volume, ft
^{3} - 43,560 is a unit conversion constant, ft
^{2}/acre - $A$ is the mapped area of the reservoir, acres
- $\overline{{h}_{g}}$ is the average gross reservoir thickness, ft

Specifically, in standard SPE (Society of Petroleum Engineers) nomenclature, we have:

and

Where:

- 5.615 is a unit conversion constant, ft
^{3}/bbl - $N$ is the Stock Tank Oil Originally In-Place (STOOIP), STB
- $G$ is the Original Gas In-Place (OGIP), SCF
- $W$ is the original water in-place, STB

Note that in **Equation 4.04a**, we used the saturation constraint, ${\Sigma}_{p}\overline{{S}_{p}}=1.0$. To use the Volumetric Method to determine the Stock Tank Oil Originally In-Place, all of the pressure dependent properties are evaluated at the initial reservoir pressure, ${p}_{i}$, as are all of the saturations, $\overline{{S}_{oi}}$,$\overline{{S}_{gi}}$, and $\overline{{S}_{wi}}$. All of the averages in these equations are averages over location (not averages over time).

The volumetric method for estimating the in-place volumes is considered to be less accurate than the material balance method. The reason for this is because of the use of all of the averages used in the volumetric method. This defect in the volumetric method can be improved by the use of an iso-contour parameter, ${I}_{cp}$. The iso-contour method calculates the composite property, ${I}_{cp}$, from the individual constituents:

The composite property, ${I}_{cp}$, is evaluated at the known at the points of * Well Control* (well locations where the properties ${h}_{n}$, ${h}_{g}$, $\varphi $, ${S}_{p}$, and ${B}_{p}$ can be measured and are assumed to be known). Since the values that make up ${I}_{cp}$ are all known at the points of well control, they can be used to evaluate ${I}_{cp}$ without any averaging. Once values of ${I}_{cp}$ are evaluated at the points of well control, they can then be averaged to determine $\overline{{I}_{cp}}$. With $\overline{{I}_{cp}}$ the fluids in-place can be calculated with:

and

This approach reduces the averaging processes from the four averages required in **Equation 4.04** to one required in **Equation 4.06**.

We will defer the discussion of the material balance method for the estimation of STOOIP until later in this lesson when we discuss field performance.