Porosity is the fraction of a rock’s total volume that is empty space (pores). It tells a petroleum engineer how much oil, gas or water a reservoir rock can store. In this article you will learn what porosity is, how it is calculated, the difference between absolute and effective porosity, and why it matters for reservoir engineering.
What Is Porosity?
The void spaces in reservoir rocks are, for the most part, the intergranular spaces between sedimentary particles. Porosity is defined as the ratio of void volume to the bulk volume of the rock, expressed as a fraction or a percentage. The proportion of void can be calculated for regular arrangements of uniform spheres, but real reservoirs are far more complex and are affected by many parameters such as grain shape, sorting and cementation. For that reason porosity is measured either in the laboratory on core samples, with conditions simulated as closely as possible, or in place with well logs such as the Neutron, Density and Sonic logs.
How Is Porosity Calculated?
Porosity (φ) is the ratio of pore volume to bulk volume:
Porosity (%) = (Pore volume ÷ Bulk volume) × 100
- Bulk volume is the total volume of the rock, including grains and pores.
- Pore volume is the volume of the spaces between the grains.
- Grain (matrix) volume = bulk volume − pore volume.
Example: a core plug has a bulk volume of 50 cm³, and its pore volume is 10 cm³. Its porosity is (10 ÷ 50) × 100 = 20%.
In practice, porosity is measured on core samples in the laboratory; see laboratory measurement of porosity.
Absolute vs. Effective Porosity
In porous rocks there are always some blind or unconnected pores. This is why two kinds of porosity are used:
| Type | What it measures | Why it matters |
|---|---|---|
| Absolute (total) porosity | All pore space, connected or not | Shows the full storage capacity of the rock |
| Effective porosity | Only the interconnected pore space | The part that can actually contribute to flow |
In reservoir engineering, only the interconnected, or effective, porosity is of interest, since this is the only capacity that can contribute to flow. Pores sealed off by cementation or recrystallization are of no interest to production.
Primary and Secondary Porosity
- Primary porosity is the void space left after the sediment grains were deposited. It is a matrix porosity.
- Secondary porosity forms after deposition, from dissolution (pits and vugs), fractures and other discontinuities in the rock. Its contribution to total porosity is generally small, yet it can dramatically increase how easily hydrocarbons flow through the rock.
Processes after sedimentation, such as cementation, recrystallization, weathering and fracturing, can substantially change the amount and distribution of pore space. See the classification of porosity for more detail.
From the reservoir engineering point of view, the important difference between primary and secondary porosity is not how they formed, but their very different flow capacity when an interconnected secondary system is present. This is called a dual porosity system, and it makes reservoir models much more complex. Engineers make practical assumptions to fit the real reservoir into a workable model.
Why Porosity Matters
- It controls the storage capacity of the reservoir, and therefore the volume of hydrocarbons in place.
- It is a key input to reserve estimates and reservoir simulation models.
- On its own, it does not tell how well fluids flow. High porosity does not always mean high flow; see the relation between porosity and permeability.
Frequently Asked Questions
What is a good porosity for a reservoir?
There is no single value. Many productive reservoirs fall roughly between 5% and 30%, and reservoirs with porosity above about 15% are generally considered good. The value must be judged together with permeability and the fluids present.
Is porosity the same as permeability?
No. Porosity is how much space the rock has. Permeability is how easily fluids can move through that space. See permeability.
How is porosity measured?
In the laboratory on core samples, or in the well with Neutron, Density and Sonic logs.
Key Takeaways
- Porosity = pore volume ÷ bulk volume.
- Effective porosity counts only connected pores and is the one that matters for flow.
- Primary porosity forms at deposition, secondary porosity forms afterwards.
- Porosity measures storage, not flow.
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