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Effects of Rock Compressibility on Field Development

Mon Nov 24, 2014 6:09 am

Even though rocks might seem rigid and uncompressible, when buried deep and are submitted to high pressures they can deform. This behavior is captured by compressibility, a parameter that can be acquired in specialized labs. The Formation, Rock or Pore Volume compressibility is an important rock property because it can add additional drive mechanisms to help expel fluids from the formation and because it can reduce the porosity and permeability of the reservoir. Rock compression thus has both negative and positive effects for hydrocarbon production.

Compressibility is expressed in terms of change in pore volume per unit pore volume per change in pressure:


Where Cf is the rock compressibility in 1/psi; PV is the pore volume and p is the pressure.

Stress acting on a reservoir
In a reservoir there a different forces acting at the same time. The largest stress is formed by the overburden rock and it’s weight causing pressure on the reservoir. A second force is caused by the fluids filling the pores of the reservoir that counter act this force as it somewhat supports the grains of the formation. The pressure of the fluids it often related to the hydrostatic gradient (typically 0.43-0.45 psi/ft), which is based on the assumption that the formation water in the reservoir is connected to the surface and is solely controlled by the weight of the overlying water (brine). For a given depth one can thus easily calculate the hydrostatic pressure. In overpressured or underpressured reservoirs this link is disrupted or blocked and the formation is no longer in hydrostatic equilibrium.

In oil and gas columns the fluid pressure is higher than the hydrostatic gradient as the buoyancy forces cause oil or gas to displace water thereby increasing the pressure at a certain depth.

These fluid pressures thus counteract the overburden pressure and their difference is called Net Overburden Pressure (NOBP) or Net Confining Pressure.

Rock Compression and Compaction of Geological time
In geological time (millions of years) the NOBP causes expulsion of fluids and the compaction of the formation. This is a constant process as rocks are buried and as long as fluids can be expelled (eg. the reservoir is not isolated, due to faults or impermeable seals) the expulsion of fluids will allow the counteracting force to be reduced and the rock to be compacted. If fluids can not escape an overpressured aquifer/reservoir is formed. If isolated aquifers are uplifted (or overburden is removed) and overburden pressure reduces, underpressured aquifers/reservoirs are formed.

Rock Compressibility during production
When a reservoir is produced and the pressure is reduced in the reservoir the counteracting force on the overburden pressure is reduced. This can lead to the rock being compressed. The effect of this compression is typically low and in the order of 3E-6 1/psi, but on a large volume this can still cause significant fluid expulsion while reducing porosity. This can add additional energy/drive to the reservoir.

On the flipside this compression will cause grains to be moved closer together and can thus reduce permeability. This can lead to lower production. The effect is shown below.


Compressibility Effects on Porosity
Several authors (Knaap and Hall) have collected compressibility data for different reservoirs and porosity ranges. Although the predictability of compressibility is difficult for most friable and unconsolidated reservoirs for consolidated reservoirs a general trend can be observed. Typically the compressibility increases as porosity decreases, which is somewhat counter intuitive as one would expect the void space that’s available for grain movement to be lower in low porosity rock.


The effect is not well understood, but potentially it could be related to the range of sizes of the particles that are present in low porosity systems. Typically they have poorly sorted grains of different sizes, that when subjected to pressures can more easily move and fill voids. This, opposed to better sorted systems with grains of similar sizes.

Compressibility Effects on Permeability
Generally compression reduces permeability but weather this effect is significant to warrant artificially maintaining pressure in a reservoir depends on the fluids traveling though the pore space (oil, water or gas) and the expected permeability reduction. Well cemented reservoirs usually experience less permeability reduction when compared to unconsolidated reservoirs, but the effect remains poorly understood and is not that predictable. Lab experiments should ideally be performed if permeability reduction is a risk for the field development.

When is Compressibility important
Compressibility is usually only a risk for significant permeability reduction when pressure is reduced with about 5,000 to 10,000 psi as at these NOBPs the effect may be a reduction of 20 to 60% in the unconsolidated of more permeable reservoirs. However, reservoirs need to be at a significant depth to allow for such a large pressure change and at those depths permeability is usually already pretty low and reservoirs are generally consolidated. One thus needs a very large gas column at significant depth before one has to worry about compressibility destroying permeability.

when compared to effects on permeability lower NOBPs are necessary to achieve significant porosity reduction and additional drive. Particularly when large aquifers are present the compression can add valuable energy to the reservoir. In some reservoirs it is known that a reduction of about 5,000 psi has led to a 40 to 30% porosity. While this is favorable for recovery it can have large consequences for the overburden, as not only will the reservoir compact, also the overburden might subside. This has led to several subsidence-related problems around the world and is something to consider when developing reservoirs.

Re: Effects of Rock Compressibility on Field Development

Thu Nov 27, 2014 12:49 am

Thanks for sharing this!

Didn't know this could have such an effect on reservoir behaviour.
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