Porosity and permeability of oil-gas reservoir rock – A review

According to the Society of Petroleum Engineers Glossary, a reservoir rock is a rock containing porosity, permeability, sufficient hydrocarbon accumulation, and a sealing mechanism to form a reservoir from which commercial flows of hydrocarbons can be produced. Porosity and permeability are the most significant physical properties of the reservoir rock. Porosity and permeability allow the migration and accumulation of petroleum under adequate trap conditions. Both of them are geometric properties that influence structural and compositional behavior (composition) reservoir rocks.

Porosity

Porosity is a measure in percentage of pore volume or size of holes per unit volume of rock. For example, well-sorted sand in a 300 ml container will hold about 100 ml of water in its pore space, or porosity of 33%. If petroleum is present, it can also occupy this pore space. During the burial of this sand, compaction reduces this porosity substantially to where only a small percentage of porosity is left.

Permeability

Permeability is a measure of the connectivity of pores in the subsurface. The sand in the container has narrow pore throats between the large pores that allow fluid to pass from one pore to another. Permeability is measured in millidarcy (md) or Darcy (1000 md) of these narrow throats. Commonly, permeability in the range of 100 to 500 md is a reasonable value for a petroleum reservoir rock. Fractures have infinite permeability.

Permeability measurement

Darcy's fundamental law is given below if water was allowed to flow downward through the sand pack contained in an iron cylinder. Manometers located at the input and output ends measured fluid pressures, which were then related to flow rates to obtain the following fundamental Darcy's law:

q = KA delta h / L

Where, where

q = water flow rate, K = constant of proportionality that is characteristic of the sand pack

A = cross-sectional area of the sand pack

Δh = h1–h2 = difference in height between the water levels in the manometers

L = length (cm)

The units in which permeability is typically expressed are the darcy (d) and millidarcy (md).

The concept is as follows: A permeability of 1 d allows the flow of 1 cm3 per second of fluid with 1 cP (centipoise) viscosity through a cross-sectional area of 1 cm2 when a pressure gradient of 1 atm/cm is applied

Reservoir rocks that contain minor or lesser amounts of in-place hydrocarbons are the minor reservoir rocks. The major reservoir rock is the second name used in the name of the petroleum system. The major reservoir rock indicates the optimum migration path between the shell of the active source rock and the traps that include the major reservoir rock. The minor reservoir rock indicates the least effective migration path. Reservoir rocks are seldom if ever found to be homogeneous in physical properties or uniform in thickness. Variation in the geologic processes of erosion, deposition, lithification, etc. dictates that reservoir rocks be heterogeneous and nonuniform. Lithification is a process of porosity destruction through compaction and cementation.

Compressibility of Porous Rocks

Reservoir rocks are subjected to the internal stress exerted by fluids in the pores, and to external stress which is in part exerted by the overlying rocks. The depletion of fluids from the reservoir rocks results in a change in the internal (hydrostatic) stress in the formation, thus causing the rock to be subjected to an increased and variable overburden load, and the result is the compaction of the rock structure due to an increase in the effective stress. This compaction results in changes in the grain, pore, and bulk volume of the rock. The fractional change in the volume of solid rock constituent (grains) per unit change in pressure is defined as the rock matrix compressibility. The fractional change in the total or bulk volume of the formation per unit change in the reservoir pressure is called the rock bulk compressibility.

Reservoir rock properties

Storativity and transmissibility

Reservoir rock characteristics are evaluated in terms of storativity and transmissibility to indicate the storage and flow potential of petroleum fluids, respectively. The two parameters combine various rock and fluid properties as in the following:

Storativity = Porosity × total compressibility × thickness

Transmissibility= [Permeability × thickness] / Fluid viscosity

Storativity indicates the amount of fluid that will be released from the porous medium when there is a unit drop in reservoir pressure. The unit of storativity is pounds per square inch (psi−1). The storativity of rock is directly proportional to effective porosity, net thickness, and total compressibility.

Larger values of the three properties lead to a greater storage of petroleum. Transmissibility is directly proportional to reservoir permeability and net thickness, and inversely proportional to fluid viscosity. The unit of transmissibility is mD-ft./cp. High values of rock permeability along with greater formation thickness and relatively low fluid viscosity lead to large volumetric flow in the porous medium that is ultimately produced through the wells. On the contrary, low reservoir permeability and viscous oil reduce the transmissibility of the rock and are hence detrimental to production.

 References

Abdus Satter, Ghulam M. Iqbal, in Reservoir Engineering, 2016

Leslie B. Magoon, in Encyclopedia of Energy, 2004

Djebbar Tiab, Erle C. Donaldson, in Petrophysics (Fourth Edition), 2016

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