BAKER HUGHES - Drilling Fluids Reference Manual

RESERVOIR APPLICATION FLUIDS
Most carbonates begin as skeletal assemblages. They are the accumulation of the remains of
carbonate secreting animals and plants. Carbonates may form on gently sloping platforms such as
continental shelves in shallow, warm saline water. The resulting rock forms layers of limestone in
the subsurface that extend spatially over great distances as in the case of the Michigan Basin or the
Cretaceous in Europe. Carbonates may also form as linear or continuous reef trends, as in the case
of the Cretaceous reef structure in South Louisiana.
Porosity and permeability are greatly reduced in ancient carbonate reservoir rocks due to
compaction and cementation. Porosity tends to increase as a result of secondary processes of
leaching and dolomitization of the limestone that occurs after the carbonate rock was formed.
Recent carbonate sediments have higher porosity values, but porosity is always reduced during
burial and compaction which may reduce the thickness of a limestone bed by 25% under no more
than a few hundred meters of overburden. Dolomitization enables a carbonate reservoir rock to
resist compaction. Dolomites are normally less porous than limestones at shallow depths, but they
retain their porosity better during burial and are less affected by compaction. Therefore they tend to
be better reservoir rocks because they contain more voids that hydrocarbons can fill.
Carbonate reservoirs represent a broader range of producibility than do the more common
sandstone reservoirs. The most prolific and sustained production rates come from carbonate
reservoirs. Carbonate reservoirs can also be at the other extreme in terms of hydrocarbon
production. Many carbonate reservoirs will not yield their oil and gas at all unless they are
artificially fractured. On average, and despite some outstanding carbonate reservoirs, sandstone
reservoirs produce more hydrocarbons per unit volume of reservoir.
Reservoir Traps
Where hydrocarbons exist today in the subsurface depends upon the juxtaposition of source rocks,
reservoir fluids, and reservoir traps. There are two types of migration when discussing the
movement of petroleum, primary and secondary. Primary migration refers to the movement of
hydrocarbons from within source rock and into reservoir rock. Secondary migration refers to the
subsequent movement of hydrocarbons within reservoir rock; the oil and gas has vacated the source
rock and has entered the reservoir rock.
A trap consists of an impervious stratum that overlies the reservoir rock thereby preventing
hydrocarbons from escaping upward and laterally. This impervious stratum is called a roof, or cap,
rock; it intervenes to collect and hold hydrocarbons underground. The roof/cap forms a seal, or
barrier, which creates the needed conditions for a pool. Trap material must have a lower
permeability than the existing rock material through which the hydrocarbons are flowing. The rock
forming the seal is also referred to as a capping bed. Porosity controls the volume of hydrocarbons
present in a given trap while permeability controls the volume of hydrocarbons that can be
extracted from the trap.
Most of the hydrocarbons that form in sediments do not find a suitable trap and eventually flow to
the surface along with formation water. It is estimated that less than 0.1% of all organic matter
originally buried becomes trapped in an oil pool. The greatest ratio of hydrocarbon pools to volume
of sediment is found in rock no older than 2.5 million years and almost 60% of all oil discovered is
found in strata of Cenozoic age.
There are three basic types of hydrocarbon traps:
BAKER HUGHES DRILLING FLUIDS
REFERENCE MANUAL
REVISION 2006 6-13