The porosity of a geological formation can vary considerably depending on the nature of the material. Some fine-grained sediments can reach porosities of up to 70%, while consolidated sedimentary rocks often range between 10 and 30% [1]. However, the availability of pore space alone is not enough to determine a reservoir's value. For a fluid to flow or be extracted efficiently, the pores must also be interconnected.
This is where permeability comes into play. Together with porosity, it is one of the two essential parameters used to assess a rock's potential to serve as an underground reservoir, whether for natural hydrogen, CO₂, geothermal energy, or dissolved minerals. Together, these properties help distinguish a rock that is simply porous from a geological formation capable of both storing fluids and allowing them to flow.
What Is Rock Porosity?
Definition and Formula
Porosity refers to the proportion of empty spaces within a rock. These spaces, known as pores, may occur between mineral grains, in small cavities, or within fractures. They represent volumes that can contain fluids such as water, oil, or gas.
Denoted by the symbol φ (phi), porosity is the ratio of the total pore volume to the total rock volume. It is expressed as a percentage using the following formula:
Porosity (%) = (Volume of Voids / Total Rock Volume) × 100
In practice, porosity depends on several geological characteristics, including grain size and arrangement, the degree of consolidation, and the changes a rock undergoes over time. It can therefore vary considerably, even within the same rock family.
For example, samples studied in 2025 exhibited porosities of 19 to 32.5% for sandstones, compared with 30.7 to 33.1% for carbonate rocks [2]. These variations can be explained in part by characteristics specific to each formation and by geological processes such as compaction, cementation, or dissolution.
To broaden this comparison, the following table presents porosity ranges reported for different sedimentary rocks [4]:
Table 1: Porosity Ranges by Sedimentary Rock Type
| Rock Type | Porosity (%) |
|---|---|
| Sandstone | 5–30 |
| Siltstone | 20–40 |
| Shale | 1–10 |
| Limestone and Dolostone | 1–25 |
| Karstic Limestone | 5–35 |
Source : Woessner et Poeter, The Groundwater Project (2020) [5].
Primary vs. Secondary Porosity
A rock's porosity can have different origins depending on its geological history. The main distinction is between primary porosity, which is present when the rock forms, and secondary porosity, which develops as a result of subsequent geological changes.
Primary porosity mainly consists of the spaces left between grains when sediments are deposited. It depends on their size, arrangement, and degree of consolidation. Fine-grained, unconsolidated sediments such as silt or clay can therefore have porosities of up to 70% [1].
Secondary porosity, on the other hand, forms after the rock has developed, when geological processes create new spaces or modify existing pores. It can take two main forms:
Dissolution porosity: This develops when minerals are dissolved by fluids flowing through the rock. The process is particularly important in limestone, where it can create cavities of various sizes, including moldic or vuggy pores.
Fracture porosity: This develops when geological stresses produce cracks or fractures in the rock. These openings can increase pore space and, when interconnected, facilitate fluid flow through formations that were initially poorly permeable [1].
Total vs. Effective Porosity
Another important distinction concerns pore connectivity. Total porosity includes all the empty spaces within a rock, whether interconnected or isolated. Effective porosity, by contrast, includes only interconnected pores—that is, spaces that can contribute to fluid flow. It is therefore generally lower than total porosity.
What Is Permeability, and How Does It Differ from Porosity?
A highly porous rock is not necessarily a good reservoir. Even when it contains many empty spaces, fluids must be able to move between those pores to be extracted or injected efficiently. This is where permeability comes into play: a property that complements porosity by describing how easily fluids can move through a geological formation.
Definition and Darcy's Law
Permeability refers to a rock's ability to allow fluids to flow under a pressure difference. It depends in particular on pore size, pore connectivity, and the complexity of the pathways they form within the rock.
This phenomenon is described by Darcy's law, established by French engineer Henry Darcy in 1856 based on experiments involving water flowing through sand. The law relates fluid flow rate to the permeability of the medium, pressure difference, flow distance, and fluid viscosity [3].
In reservoir engineering, intrinsic permeability is generally expressed in darcys (D) or millidarcys (mD), with 1 D = 1,000 mD. By its conventional definition, one darcy corresponds to a flow of 1 cm³ of fluid per second through an area of 1 cm², under a pressure gradient of 1 atm/cm, for a fluid viscosity of 1 cP [3].
The millidarcy is commonly used to characterize reservoir rocks, whose permeability is often below 1 darcy.
Porosity and Permeability — Two Roles, Two Measurements
Although closely related, porosity and permeability describe two different characteristics of a reservoir:
Porosity represents the proportion of empty spaces within a rock and helps estimate the volume potentially available to contain fluids.
Permeability indicates how easily those fluids can pass through the rock, influencing injection and extraction flow rates.
Clay provides a good example of this distinction. Some unconsolidated clay-rich sediments can have porosities reaching 70%, but their extremely small pores and the interactions between water and minerals significantly restrict fluid flow [1].
Conversely, dense crystalline rock may have very low matrix porosity while still allowing substantial fluid flow when crossed by an interconnected network of natural fractures [13].
Reservoir quality therefore depends on the combination of these two properties. Sufficient effective porosity provides the space needed to store fluids, while adequate permeability allows them to circulate under the intended operating conditions.
Table 2: Indicative Hydraulic Conductivity by Lithology
| Lithology | Main Flow Mechanism |
|---|---|
| Gravel | Intergranular |
| Sand | Intergranular |
| Clay | Intergranular |
| Limestone / dolostone | Variable |
| Karstic limestone | Dissolution and fractures |
| Dense crystalline rock | Matrix flow |
| Fractured crystalline rock | Fractures |
Source: British Geological Survey, 2006 [13]
How Do Diagenesis and Fracturing Change These Properties Over Time?
A rock's porosity and permeability do not remain fixed over time. Throughout its geological history, a formation may undergo physical and chemical changes that alter the size, volume, and connectivity of its pores. These changes can increase or decrease its ability to store fluids and allow them to flow.
Diagenesis — Compaction, Cementation, and Dissolution
Diagenesis encompasses the changes sediments undergo after deposition, particularly during burial and consolidation into rock. These processes directly influence reservoir properties, sometimes in opposing ways.
Three mechanisms are particularly important:
Compaction: Under the weight of accumulating sedimentary layers, grains move closer together and some pore fluids are expelled. Pore volume decreases, generally reducing porosity and permeability [9].
Cementation: Minerals dissolved in fluids precipitate between grains, progressively filling some of the pore spaces. This process, common in sedimentary rocks, can reduce their storage capacity and restrict fluid flow [9].
Dissolution: Conversely, certain minerals can be dissolved by fluids moving through the rock. New cavities form or existing pores expand, increasing porosity locally and, when these spaces are sufficiently interconnected, permeability [10].
Reservoir evolution also depends on the sequence of these changes: a dissolution phase occurring after cementation, for example, can produce a different porosity–permeability relationship than would be expected from a simpler model [10].
Fracturing — New Pathways for Fluids
Natural fracturing can also change the properties of a geological formation. Under tectonic stresses or other geological processes, cracks and fractures may develop in rocks that were initially poorly permeable.
When these fractures form an interconnected network, they create new pathways for fluid flow, sometimes without significantly increasing total porosity [9].
Why Are These Properties Essential in Energy and Resource Reservoirs?
Whether the goal is to extract natural hydrogen, store CO₂, harness subsurface heat, or recover lithium from brines, the porosity and permeability of the host rock directly influence the technical feasibility of each project.
Natural Hydrogen — Accumulation and Underground H₂ Storage
In the field of natural hydrogen, porosity and permeability help determine where H₂ can migrate and accumulate. Exploration notably involves identifying reservoir rocks capable of containing hydrogen and caprocks that limit its migration toward the surface.
These properties are also important for underground hydrogen storage. Injection and withdrawal cycles can progressively alter pore structure and rock permeability. Tests on limestone samples have shown permeability decreases of up to one order of magnitude under certain loading conditions [5].
Geological CO₂ Storage (CCUS) — Injection and Containment
Geological CO₂ storage involves injecting carbon dioxide into deep geological formations, generally in a supercritical state. Sufficient porosity provides space for CO₂, while adequate permeability facilitates its injection and distribution within the reservoir. A low-permeability caprock then helps contain it [6].
Site selection also requires careful control of injection pressures to limit fracturing risks and preserve the integrity of the storage system [7].
Geothermal Energy — Harnessing Subsurface Heat
In geothermal energy, porosity determines, among other things, the space available to contain hot fluids, while permeability influences their circulation and the transfer of heat to the surface [8].
In naturally low-permeability formations, enhanced geothermal systems (EGS) aim to improve circulation by creating or reactivating fractures in hot rock. This approach makes it possible to consider geothermal resources beyond naturally permeable reservoirs.
Critical Minerals in Solution — Lithium and Heap Leaching
Porosity and permeability also play a role in critical mineral extraction, particularly in two applications:
Lithium brines: Found in certain aquifers, these require characterization of porosity, reservoir geometry, and lithium concentration. In salars, specific yield is also important for estimating the volumes of brine that could potentially be recovered [11].
Heap leaching: This method involves circulating a solution through a heap of crushed ore to extract metals. Low permeability can reduce process efficiency, particularly for copper and gold. Removing fine particles or agglomerating them can help improve fluid flow [12].
Toward a Better Understanding of the Subsurface
Porosity and permeability are distinct yet inseparable properties when assessing a reservoir's potential. The former indicates a rock's capacity to store a fluid, while the latter determines whether that fluid can flow and be recovered. An exploitable formation must therefore combine sufficient pore volume with effective connectivity between pores.
Long studied in the oil and gas industry, these properties now play a central role in several energy transition applications, from geological CO₂ storage and geothermal energy to natural hydrogen and brines rich in critical minerals. Carefully evaluating them remains essential to understanding the true value of the subsurface.
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References
[1] Earle, Steven. « 14.1 Groundwater and Aquifers. » Physical Geology – 2nd Edition, BCcampus, 2019, https://opentextbc.ca/physicalgeology2ed/chapter/14-1-groundwater-and-aquifers/.
[2] Sharanik, Jumana, Ernestos Sarris, and Constantinos Hadjistassou. « Storage and Production Aspects of Reservoir Fluids in Sedimentary Core Rocks. » Geosciences, vol. 15, no. 10, 2025, article 386, https://doi.org/10.3390/geosciences15100386.
[3] « Darcy (Unit). » Wikipedia, Wikimedia Foundation, https://en.wikipedia.org/wiki/Darcy_(unit).
[4] Woessner, William W., and Eileen P. Poeter. Hydrogeologic Properties of Earth Materials and Principles of Groundwater Flow. The Groundwater Project, 2020, https://doi.org/10.21083/978-1-7770541-2-0.
[5] Xu, Zhaochen, et al. « Porosity-Permeability Evolution of Carbonate Rocks Under Cyclic Hydrostatic Loading: Creep-Fatigue Interaction and Implications for Hydrogen Storage. » Journal of Geophysical Research: Solid Earth, vol. 131, no 5, 2026, article e2025JB033646, https://doi.org/10.1029/2025JB033646.
[6] National Academies of Sciences, Engineering, and Medicine. « Sequestration of Supercritical CO₂ in Deep Sedimentary Geological Formations. » Negative Emissions Technologies and Reliable Sequestration: A Research Agenda, chap. 7, National Academies Press, 2018, https://www.ncbi.nlm.nih.gov/books/NBK541452/.
[7] U.S. Environmental Protection Agency. Geologic Sequestration of Carbon Dioxide in Deep Saline Formations: Report to Congress. Jan. 2025, https://www.epa.gov/system/files/documents/2025-01/deepsalineformation_rtc_jan2025.pdf.
[8] Moscardini, Rioko. « What Makes a Good Geothermal Reservoir? » GeoEnergy NI, 2024, https://geoenergyni.org/geothermal-reservoir/.
[9] « Promoting Burial Diagenesis. » Geological Digressions, 17 Feb. 2026, https://www.geological-digressions.com/promoting-burial-diagenesis/.
[10] Hosa, Ola, and Rachel Wood. « Order of Diagenetic Events Controls Evolution of Porosity and Permeability in Carbonates. » Sedimentology, 2020, https://doi.org/10.1111/sed.12733.
[11] Houston, John, et al. « The Evaluation of Brine Prospects and the Requirement for Modifications to Filing Standards. » Economic Geology, vol. 106, no. 7, 2011, pp. 1225–1239, https://doi.org/10.2113/econgeo.106.7.1225.
[12] Robertson, S. W., et al. « Properties Governing the Flow of Solution Through Crushed Ore for Heap Leaching: Part III – Low-Permeability Ores. » Hydrometallurgy, vol. 224, 2024, article 106247, https://doi.org/10.1016/j.hydromet.2023.106247.
[13] Lewis, M. A., et al. Guide to Permeability Indices. British Geological Survey Open Report CR/06/160N, British Geological Survey, 2006, https://nora.nerc.ac.uk/id/eprint/7457/1/CR06160N.pdf.
