- 1.1 Introduction
- 1.2 Total Porosity and Effective Porosity
- 1.3 Sources of Porosity Data
- 1.4 Applications of Porosity Data
- Nomenclature
- Abbreviations
- References
- General Reading
This chapter is from the book
This chapter is from the book
This chapter is from the book
1.4 Applications of Porosity Data
One of the primary rock property data used in most reservoir evaluation is porosity data. Consequently, it is important that accurate values of porosity data for the reservoir rocks are measured and validated by other independent methods. Porosity data are used in these basic reservoir evaluations:
- Volumetric calculation of fluids in the reservoir
- Calculation of fluid saturations
- Geologic characterization of the reservoir
1.4.1 Volumetric Calculation
A general formula for the calculation of the volume of hydrocarbons in a reservoir is represented as:
Equation 1.17
In Eq. (1.17), HCPV = hydrocarbon pore volume; Area = hydrocarbon-bearing area of the reservoir; Thickness = net productive thickness or pay of the reservoir; f = porosity, fraction; and Sw = water saturation, fraction. The hydrocarbon volumes of specific types of fluids (oil and/or gas) in the reservoir can be calculated with minor modifications of Eq. (1.17) as demonstrated in Chapter 8 for Gas Reservoirs, and Chapter 9 for Oil Reservoirs. Note the prominence of porosity in Eq. (1.17) for the calculation of volumes of hydrocarbons present in a reservoir. It is evident from Eq. (1.17) that inaccurate porosity data can directly cause underestimation or overestimation of the hydrocarbon volumes in the reservoir. For marginal reservoirs, underestimation of in-place hydrocarbon volumes may contribute to a decision not to pursue development of the reservoir. Overestimation of in-place hydrocarbon volumes may lead to economic losses, if projected reserves estimated prior to development are far below actual reservoir performance. Note that there are other geologic and reservoir factors (such as permeability barriers, faults, compartments, recovery mechanisms) which can also cause reservoir performance to be below projected levels. The impact of these other factors on reservoir performance are presented and discussed in more details in several chapters in this book.
1.4.2 Calculation of Fluid Saturations
For clean, non-shaly rocks, water saturations can be calculated from the Archie equation1 as:
Equation 1.18
In Eq. (1.18), Ct = formation conductivity; f t = total porosity; Sw = water saturation; Cw = formation water conductivity; m = cementation factor; and n = saturation exponent. The parameters m and n are also called the electrical properties of the rock.
For shaly sands, water saturations can be calculated from modified forms1 of the Archie equation, which are shown as:
Equation 1.19
Equation 1.20
In Eqs. (1.19) and (1.20), Cwe = effective conductivity; and mv , nv are general forms of the electrical properties. In Eq. (1.19), Cwe is expressed in terms of Cw and a function of shale (in the shale model) or a function of clay (in the clay model). In Eq. (1.20), X is a function that accounts for the conductivity caused by shale or clay that occur in shaly sands. Note that in Eq. (1.20) as X approaches zero, Eq. (1.20) becomes equivalent to Eq. (1.18).
The main point to note from Eqs. (1.18), (1.19), and (1.20) is that total porosity is an important data input for calculation of water saturation with water saturation models. If errors exist in the calculations of total porosity, these errors will be transferred to the calculation of water saturations. This could ultimately lead to errors in the estimation of reservoir in place hydrocarbon volumes as shown in Eq. (1.17). The calculation of water (fluid) saturation is presented in more detail in Chapter 3.
1.4.3 Reservoir Characterization
Porosities can be measured directly from cores or indirectly determined from well logs as discussed previously in this chapter. On the one hand, rock permeability can be measured most reliably from cores or in aggregate sense from well tests. Indirect methods for acquiring permeability data are discussed in Chapter 2. There are usually more porosity data than permeability data available on a reservoir. A cross-plot of permeability versus porosity data (Figure 1.4) to create a porosity-permeability transform is sometimes used to assign permeability values to areas of the reservoir where permeability data do not exist. The practice of using porosity-permeability transforms in reservoir characterization is presented in Chapter 18.
)
Figure 1.4 Porosity-permeability cross-plot based on core samples from a reservoir.
Facies or rock types can be defined or assigned to parts of a reservoir by using porosity values as part of a system of criteria for rock classification. This process of classifying reservoir rock in terms of facies or rock types is useful in the process of reservoir characterization. This is also presented in Chapter 18.