Page 15 - Well Control for Completions and Interventions

10 Well Control for Completions and Interventions

Table 1.2 Porosity values for sandstone and carbonate material
Formation ɸ Range (%) Typical average (%) Normal economic
limit (%)
Sandstone 8 39 18 8
Carbonates 3 50 8 3 5

1. The capacity for storage (porosity).
2. The transmissibility of fluids (permeability).
Porosity is a measure of the storage capacity of a formation, and is
directly related to the volume of void space in the reservoir rock.
Voids occur at intergranular gaps between the grains, and are termed
pores. Porosity is defined as the percentage or fraction of the void space
to the total bulk volume of the rock, and is normally indicated using the
symbol ɸ (phi). Porosity varies enormously (Table 1.2).
Porosity alone is not enough to make a formation commercially via-
ble. Hydrocarbons must be able to flow through the formation and reach
the wellbore. This can only happen if there is interconnectivity between
pore spaces allowing fluids to flow. Permeability is a measure of flow
capacity through a formation, and can only be determined by flow
experiments using core from the reservoir. Since permeability depends
upon the continuity of pore space, there is no unique relationship
between porosity and permeability (Fig. 1.5).
Permeability is represented by the Greek letter k (kappa). Reservoir
permeability is most commonly measured in Darcy (D) or millidarcy
(mD). The coefficient of permeability (k) is a characteristic of the rock,
and is independent of the fluid used for measurement. Rock has a perme-
ability of 1 D, if a pressure gradient of 1 atm/cm induces a flow rate of
3 2
1cm /s across a cross-sectional area of 1 cm using a liquid with a viscos-
ity of 1 cP (fresh water). Since most oilfield reservoirs have permeabilities
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that are less than 1 D, the millidarcy (10 D) is more commonly used.
To relate this to oilfield applications and hydrocarbon reservoirs,
20/40 mesh gravel, of the type used in propped fracs and sand control
completions, has an unstressed permeability of approximately 120 D
(120,000 mD). By contrast, unconsolidated well sorted course sandstone
formation might have a permeability of, e.g., 5 or 6 D. Compacted,
poorly sorted sandstones will have much lower permeability, and must be
measured in millidarcy. The shale gas reservoirs currently being exploited
in North America, whilst having good porosity, have very poor