Oil Recovery Methods:
1) Primary Recovery: Oil is transported to the surface by a naturally driving force.
Solution gas drive
Gas cap drive
Water drive
2) Secondary Recovery: Pressure is maintained by injecting a fluid into the reservoir to
replenish the fluid that is produced.
Water flooding
Gas flooding
3) Tertiary (enhanced) Recovery: This method uses a chemical-based technique to
produced oil. These methods are often used in conjunction with gas or water flooding.
A)
Non-thermal
Miscible flooding
Polymer flooding
Surfactant flooding
B)
Thermal
Steam injection
Steam flooding
Steam assisted gravity drainage (SAGD)
In-situ combustion
Primary Recovery: Oil is transported to the surface by a naturally driving
force. There are three primary driving forces:
1) Solution Gas Drive: Oil contains dissolved gases that will be liberated
with the reduction in pressure that occurs with oil production. The gas
fraction increases as oil travels from the reservoir to the well head.
Bouyant forces cause the gas bubbles to rise. Oil is entrained with the
gas phase (gas lift). The oil recovery efficiency with this mechanism is 5
to 30 % of the original oil in place (OOIP).
Rapid decline in reservoir pressure.
Producing GOR(gas oil ratio) starts low.
then increases to a max and finally drops (reservoir blow-down).
Negligible water production.
Artificial lift needed in early production life.
2) Gas Cap Drive:
With this mechanism, the gas cap applies enough pressure to the oil phase to
cause it to naturally flow through the well. The volume of the gas cap must
be comparable to the volume of oil so that the reservoir pressure is not
significantly reduced when the gas expands into the volume in the reservoir
left by the produced oil. Oil recovery efficiencies of 20 to 40 % of the OOIP
are typical.
As P drops due to production, gas cap expands down.
P support from gas cap depends on its size.
Slow decline in reservoir P.
Continuous rise in producing GOR.
Negligible water production.
Depending on size of gas cap and P support schemes, well can flow
naturally longer.
Water Drive:
When the water phase within a reservoir is linked with an aquifer, it can
provide pressure to drive the oil from the reservoir to the well head. In this
case, the water phase will replenish the reservoir volume left by the
produced oil. Typical oil recovery efficiencies are 35 to 75% of the OOIP.
Common types of aquifer: bottom and edge.
Reservoir P remains high (depends on aquifer strength).
Producing GOR is unchanged until reservoir P declines below bubble point.
Water production starts early.
Water disposal costs can be high.
Estimation of primary recovery
By: Guthrie and Greenberger
ER  0.2719 log k  0.255569SW  0.1355 log 0  1.538  0.0003488h  0.11403
ER:
Sw:
μ0:
k:
Φ:
h:
Secondary Recovery: Pressure is maintained by injecting a fluid into the
reservoir to replenish the fluid being produced.
1) Water Flooding:
This is the most common method of secondary recovery. Holes are
strategically drilled such that injected water drives oil toward the production
well. A specific geometry is typically used to drill the injection and well
holes.
Water is cheapest flooding agent.
The need to dispose of produced water.
Easy and safe to inject.
Proven technology.
Hole Patterns:
2) Gas Flooding:
Gas flooding is similar to water flooding except that the driving fluid is
natural gas rather than water.
Tertiary (Enhanced) Recovery: This method uses a chemical-based
technique to produce oil. These methods are often used in conjunction with
gas or water flooding.
A) Non-Thermal Methods:
1) Miscible Flooding:
A specific volume or slug of solvent is injected, which is followed by water
or gas flooding. The solvent acts to reduce the viscosity of the oil, which
reduces its resistance to flow. Typical solvents include C3H8, LPG
(liquefied petroleum gas: C2 to C4), or CO2. They combine with the oil
phase to become a single fluid phase.
2) Polymer Flooding:
Similar to water flooding where a slug of immiscible fluid is injected
followed by water flooding. The high viscosity injected fluid pushes the oil
phase through the reservoir resulting in higher recovery levels. Typical
polymers are xantham gum or hydrolyzed polyacrylamide. Polymers are
mixed with water to prepare the injection fluid.
3) Surfactant Flooding: This technique is very similar to water flooding.
The action of the surfactant can change the wetting properties of the
reservoir rock from oil-wetting to water-wetting. This frees the oil which is
attached to the rock resulting in higher oil recovery. Surfactants, in some
cases, will help to stabilize oil/water mixtures resulting in a lower viscosity
mixture. This further enhances recovery.
B) Thermal Methods: These methods are commonly used to produce
heavy oil.
1) Steam Injection:
Heat is supplied by steam to the heavy oil to reduce its viscosity. In the case
of steam injection, a single well is used to first inject the steam. After a finite
period of time, oil is produced from the same well. This steam stimulation
method, where injection and production are cycled, is known as “Huff and
Puff”.
2) Steam Flooding:
One well is used to inject steam and a second well is used to produce the oil.
3) Steam assisted gravity drainage (SAGD):
A steam chamber is formed in a horizontal injector well. Oil is produced
from a parallel horizontal well below the injector.
Flow is caused by gravity
Large oil recovery (50-60% of OOIP)
Low steam/oil ratio (SOR)
High productivity (0.25-0.5 m3/d/m)
m:
4) In-situ Combustion (Fire Flooding):
This in-situ (ie. within reservoir) method is initiated by causing combustion of the
petroleum underground. This is followed by the introduction of air to the reservoir to
sustain combustion. The combustion process provides heat, steam and gases which
reduce the oil viscosity, resulting in higher production rates from the well.
Even with all the different recovery techniques, only about 30% of the total amount of
Western Canadian Original Oil in Place can be produced.