It’s not enough to find oil or gas in a reservoir. The next question to answer is how much was found. This is because the volume of hydrocarbons present in the reservoir will determine whether to complete the well or to plug and abandon the well and move on. A key component of that decision is the rock's porosity.

Rock Porosity

Porosity is a term that helps to describe the amount of hydrocarbons that a rock can potentially hold. It is a measure of the fluid holding capacity of a rock. This means that rocks with greater porosity will potentially hold more hydrocarbons.


Porosity = Pore Volume, Vp / Bulk Volume, Vb

What then is the pore volume? It is the volume of the entire rock that is composed of only spaces.

As an analogy, imagine a stack of 16 soccer balls with balls lying on top of each other. There will be spaces in between balls because of the packing arrangement.

A diagram of a stack of soccer balls with pores between each ball.

Figure 1. A stack of soccer balls with pores between each ball.

The totality of these pore spaces make up the pore volume. The balls, on the other hand, make up the grain volume. When we consider the volume of the entire stack of balls then we are referring to the bulk volume. As calculated in the equation above, the porosity of the stack of balls is the pore volume divided by the bulk volume. This is the same with some rocks. Rocks with spaces in between the grains are porous rocks.

Understand though that a rock does not need to hold a fluid (oil, water or gas) in its pores to be considered porous. Consider samples of clay and loose sand. Clay has pores and easily allows water to enter the pores, but it will hold onto this water tightly and will not readily allow the water leave its pores. Loose sand will also allow the water into its pores, but finds it difficult to retain the water within its pores. So as the water enters the sand almost all of it will leave if there is no external barrier (e.g., a container) to hold the water.

Both of these rocks are porous. Porosity is only concerned with the volume of space in a rock available for fluids; porosity doesn’t go further to measure the likelihood of the fluid remaining in the pores or leaving almost immediately after it enters.

To understand how fluids flow within rocks, we’ll have to consider permeability. (This topic is discussed in depth in the article Grasping the Concept of Rock Permeability.)

An Example of a Reservoir with a Porosity of 35%

Recall that:

Porosity = Pore Volume, Vp / Bulk Volume, Vb

The ratio in the equation is normally multiplied by 100 to convert porosity to a percentage. It’s easier to look at it in terms of percentages. When we say the porosity of a reservoir rock is 35%, we mean that 35% of that rock has the potential to contain hydrocarbon fluids in its pores.

Notice that we say the rock has a potential to hold hydrocarbon fluids. This is because not all the available pore space in a reservoir rock will contain hydrocarbons. Some pore spaces may simply be empty and contain nothing at all. Other pore spaces in the rock may contain water. So when told that a rock has a porosity of 35%, the next question should be “is it the absolute porosity or the effective porosity?”

Effective Porosity

A rock may have a porosity of 35%, but some pores may not actually contains fluids. Some pores are so surrounded by rock grains cemented together that is impossible for any fluid to migrate into the pores. These pores are isolated from others and have no contact with other pores, thus they are called isolated pores. They do not contribute to fluid flow, and hence are not part of the effective porosity of that rock.

At other locations some pores may contain water, but the water is bound tightly to clay minerals in the rock matrix so the water will not flow from the reservoir. These fluids are considered lost. Pores like these won’t make the cut because they contain fluids that cannot flow. They are not part of the effective porosity of the rock. For a pore to be considered when measuring effective porosity, two conditions must be met: the pore must contain fluids (oil, water or gas) and the fluid should contribute to flow.

Absolute Porosity

Absolute porosity measures every available pore space in the rock - both the isolated pores plus the ones occupied by clay bound water. Consequently, the absolute porosity is usually greater than the effective porosity. In reality, effective porosity is never equal to absolute porosity because there is always some clay-bound water or isolated pores scattered around the reservoir.

Absolute porosity tells us the fluid holding potential of the rock, but sadly some rocks don’t always reach their full potential. (learn how to help rocks reach their full potential in The Different Ways of Perforating a Well.) Because we are concerned with how much hydrocarbon we can produce from the reservoir rock, we are usually more concerned with the effective porosity.

A diagram comparing the porosity in different types of soils and rocks.

Figure 2. Comparison of porosity in different types of soils and rocks.


Porosity is a significant factor when estimating how much fluid a rock can hold. It is the fluid holding capacity of a rock. However, some rocks may not live up to their full potential, which is why effective porosity is always less than absolute porosity. Not every pore space in a rock is available to be occupied by fluids; some are isolated from others by cemented rocks grains and others contain clay that tightly holds fluids on their surfaces. The effective porosity is an important ingredient when determining the original hydrocarbon in place.