2 Key ingredients for petroleum accumulation
2.2 Reservoir rocks
The properties of a petroleum reservoir rock are very similar to those of an aquifer since both petroleum and water can be contained within and move between its pore spaces and fractures. Sedimentary rocks that are well cemented have only small voids between grains and hence low porosity.
The most porous reservoir rocks are generally well-sorted, poorly cemented sandstones (see Figure 3b), and these make up some of the most important petroleum reservoirs around the world.
Migrating waters can increase porosity and permeability by dissolving the cement that holds the grains together and widening small fractures that run through the rock. This effect is often enhanced if the waters are slightly acidic. Many limestones are well cemented and therefore have low porosity, but the calcium carbonate (CaCO3) that makes up the grains and cement is soluble in weakly acidic water. Consequently limestones can form good reservoirs, and in fact limestones hold 40% of the world's resources of petroleum.
The essential properties that describe a reservoir rock are porosity (the void space expressed as a percentage) and permeability (a measure of the degree to which fluid passes through it, measured in millidarcies, mD). Another property that is commonly used is the ratio of porous and permeable (net) intervals to the overall reservoir (gross) thickness. This is referred to as net to gross and it is important because it recognises that most sandstone and limestone reservoirs are not entirely homogeneous, but contain intervals or strata that less readily allow fluid flow.
To put these properties in context, Table 3 provides reservoir data for 20 oil and gas fields in the North Sea. Note the very wide range of net to gross and permeability values, despite the fact that most of the reservoirs are of the same (sandstone) type. Porosities are typically in the range 15–30%, but the more telling parameter is permeability because that largely determines petroleum flow rates. Permeability cut-offs of 1 mD for gas and 10 mD for light oil are often used as a rule-of-thumb for productive reservoirs; less permeable rocks are not usually capable of sustaining commercial flow rates. Notice also that one of the two Cretaceous Chalk reservoirs in the Ekofisk field exhibits chalk's characteristic properties of high porosity and low permeability – the latter results from very small channels that connect the pores between the tiny calcareous plankton shells that form chalky sediments. The other chalk reservoir in Ekofisk has higher permeability because it has been fractured tectonically.
Table 3: Properties of reservoirs within North Sea oil and gas fields. Note: A formation is a distinctive sequence of sedimentary rocks in a particular field.
|Field||Age/Formation||Reservoir||Net to gross/%||Porosity/%||Permeability/mD||Fluid|
|Britannia||Cretaceous/Britannia||sandstone||30||15||60||gas in liquid form under high pressures|
|Buchan||Devonian/Old Red||fractured sandstone||82||9||38||oil|
|Ekofisk||Cretaceous/Chalk||limestone (Chalk)||62||30||2||oil and gas|
Using the information in Table 3, calculate the average porosity of the five Permian sandstone reservoirs and the three Palaeocene-Eocene sandstone reservoirs. Compare the results and suggest reasons for the marked difference.
The average porosity of the Permian sandstone reservoirs is (19+18+13+13+12)/5 = 15%, whereas the Palaeocene-Eocene reservoirs average (20+27+29)/3 = 25%. The simplest explanation for this difference is that younger reservoirs tend to have higher porosities because they usually occur at shallower depths and are less compacted than their older counterparts.