Fracture Permeability

Fracture permeability is the part of a reservoir's total flow capacity that comes from open natural cracks in the rock, rather than from the connected pore space inside the rock matrix. In a dual-porosity reservoir, oil or gas can travel through two different highway systems at the same time: the slow back roads of the matrix, and the fast express lanes of the natural fractures. Fracture permeability is what makes the express lanes work. It can be much higher than matrix permeability, sometimes by a factor of a thousand or more, which makes fractured reservoirs unusually productive while their pressure declines unusually quickly. Carbonate reservoirs with significant fracture permeability include many of the giant fields of the Middle East and the Devonian carbonates of Western Canada. Tight oil and gas plays like the Bakken Formation and the Eagle Ford Shale also depend heavily on natural fractures, supplemented by artificial hydraulic fractures, to deliver economic production rates.

What Fracture Permeability Means in Practice

Imagine a sponge with a few thin cracks running through it. Water poured onto the sponge can travel two ways. It can soak slowly into the porous body of the sponge itself, working its way through the connected tiny holes. Or it can run quickly through the cracks, which offer almost no resistance compared to the body of the sponge. Most of the water volume ends up in the body of the sponge eventually, but the fast initial movement happens in the cracks.

A fractured reservoir works the same way. Oil or gas in the rock matrix has to travel through tiny pore throats from one pore to the next, moving slowly through what petroleum engineers call matrix permeability. Oil or gas in an open natural fracture has almost no flow restriction and can travel as fast as the pressure gradient drives it. When a well is drilled into a fractured reservoir, the wellbore typically intersects multiple fractures. Fluid from the matrix leaks into those fractures, then races down them to the wellbore at high velocity.

The result is a flow system with two timescales. Fast flow through fractures dominates short-term well behavior. Slow flow from matrix to fractures dominates long-term recovery. A well's production curve in a fractured reservoir often shows a high initial rate followed by a steep decline, then a long tail at lower rate as the matrix slowly drains through the fracture network.

Where Fracture Permeability Drives the Reservoir

Carbonate reservoirs in tectonically active regions tend to be highly fractured. The Asmari Limestone in Iran, the Mauddud and Mishrif limestones across the Middle East, the Khuff carbonates beneath Saudi Arabia and Qatar, and the Devonian Leduc and Nisku reefs of Alberta and British Columbia all rely heavily on fracture permeability for their flow capacity. In some of these reservoirs the matrix is so tight that without fractures the rock would be considered non-reservoir at all. The fractures convert otherwise uncommercial rock into world-class producing fields.

Tight oil and gas plays are the modern variation on the same theme. The Bakken, the Three Forks, the Eagle Ford, the Permian's Wolfcamp and Spraberry, the Montney, the Marcellus, the Vaca Muerta in Argentina all have matrix permeabilities measured in nanodarcies, far below what conventional reservoir engineering would call producible. Their economic viability depends on natural fracture networks (where present) and on artificially induced hydraulic fractures (always required) to create the high-permeability flow paths that bring hydrocarbons to the wellbore. Operators map natural fracture networks aggressively because completions placed where natural fractures help often outperform completions placed where they do not.

Production engineering in fractured reservoirs is its own specialty. Material balance calculations have to handle the dual-porosity nature of the reserves. Reservoir simulation models use specialized dual-porosity or dual-permeability formulations. Waterflood and gas injection design has to account for the risk that injected fluid can race down fractures from injectors to producers without sweeping the matrix in between. Operators in mature carbonate fields have spent decades developing the tools and the operational practices to manage this complexity.

Synonyms and Related Terminology

Fracture permeability is sometimes called secondary permeability, fracture-network permeability, or open-fracture permeability. The contrasting term is matrix permeability or primary permeability. Related terms include dual porosity (the conceptual model of a reservoir that contains two distinct pore systems, the matrix and the fracture network, with different permeabilities and storage capacities; the standard framework for analyzing fractured reservoirs), natural fractures (cracks in reservoir rock created by tectonic stress, regional deformation, or rock-mechanical responses to burial; the source of the high-permeability flow paths that fracture permeability describes), hydraulic fracturing (the operational technique of pumping fluid into a well at high pressure to create artificial fractures in the formation; the necessary supplement to natural fracture permeability in tight oil and gas plays), formation microimager (FMI, a high-resolution borehole image logging tool that maps natural fractures intersecting the wellbore by measuring micro-resistivity contrasts; the primary diagnostic tool for fracture characterization), and permeability (the general property of a porous medium that quantifies how easily fluid flows through it; fracture permeability and matrix permeability are two contributing components of total reservoir permeability).

Why a Few Open Cracks Can Outproduce a Whole Reservoir of Tight Rock

A development team is appraising a Devonian carbonate prospect in northeastern British Columbia. Two appraisal wells have been drilled. Well A penetrated the reservoir, encountered tight matrix with permeability around 0.4 millidarcies, and produced 95 barrels per day on initial test. Well B, drilled 1.2 kilometres away in the same formation, encountered very similar matrix properties, but the FMI image log showed a dense cluster of open natural fractures intersecting the wellbore. Well B produced 1,640 barrels per day on initial test. Same reservoir. Same matrix permeability. Different fracture network at the well location.

The development team faces a question. Should they assume the rest of the field is more like Well A or more like Well B? The answer determines whether the field gets developed at all. The reservoir engineer integrates the FMI data with regional structural mapping to identify fault corridors that are likely associated with intense fracturing. The development plan ends up with wells located deliberately along these fault corridors rather than uniformly across the field.

Three years later, the field is producing 31,000 barrels per day from 24 wells. The wells located near the mapped fault corridors average 1,800 barrels per day each. The wells located away from the corridors average 320 barrels per day each. The five-fold productivity contrast is entirely a story of fracture permeability. The matrix is the same rock everywhere. The fractures are not. Mapping where they are, and drilling toward them, is what made the field economic.