131
Exploration, Recovery, and Transportation
into the well on a string of 6 in. (inner diameter) steel rods known as sucker rods. The up-and-down
movement of the sucker rods forces the oil up the tubing to the surface. A walking beam powered
by a nearby engine may supply this vertical movement, or it may be brought about through the use
of a pump jack, which is connected to a central power source by means of pull rods. Electrically
powered centrifugal pumps and submersible pumps (both pump and motor are in the well at the
bottom of the tubing) have proven their production capabilities in numerous applications.
There are also secondary oil recovery operations that involve the injection of water or gas into
the reservoir. When water is used the process is called a waterflood; with gas, a gasflood. Separate
wells are usually used for injection and production. The injected fluids maintain reservoir pressure
or repressure the reservoir after primary depletion and displace a portion of the remaining crude oil
to production wells. In fact, the first method recommended for improving the recovery of oil was
probably the reinjection of natural gas, and there are indications that gas injection was utilized for
this purpose before 1900 (Craft and Hawkins, 1959; Frick, 1962). These early practices were implemented to increase the immediate productivity and are therefore classified as pressure maintenance
projects. Recent gas injection techniques have been devised to increase the ultimate recovery, thus
qualifying as secondary recovery projects.
In secondary recovery, the injected fluid must dislodge the oil and propel it toward the production wells. Reservoir energy must also be increased to displace the oil. Using techniques such as gas
and water injection, there is no change in the state of oil. Similarly, there is no change in the state of
the oil during miscible fluid displacement technologies. The analogy that might be used is that of a
swimmer (in water) in which there is no change to the natural state of the human body.
Thus the success of secondary recovery processes depends on the mechanism by which the
injected fluid displaces the oil (displacement efficiency) and on the volume of the reservoir that
the injected fluid enters (conformance or sweep efficiency). In most proposed secondary projects,
water does both these things more effectively than gas. It must be decided if the use of gas offers
any economic advantages because of availability and relative ease of injection. In reservoirs with
high permeability and high vertical span, the injection of gas may result in high recovery factors
as a result of gravity segregation, as described in a later section. However, if the reservoir lacks
either adequate vertical permeability or the possibility for gravity segregation, a frontal drive
similar to that used for water injection can be used (dispersed gas injection). Thus, dispersed gas
injection is anticipated to be more effective in reservoirs that are relatively thin and have little dip.
Injection into the top of the formation (or into the gas cap) is more successful in reservoirs with
higher vertical permeability (200 md or more) and enough vertical relief to allow the gas cap to
displace the oil downward.
Vaporization is another recovery mechanism used to inject gas into oil reservoirs. A portion of
the oil affected by the dry injection gas is vaporized into the oil and transported to the production
wells in the vapor phase. In some instances this mechanism has been responsible for a substantial
amount of the secondary oil produced.
During the withdrawal of fluids from a well, it is usual practice to maintain pressures in the
reservoir at or near the original levels by pumping either gas or water into the reservoir as the
hydrocarbons are withdrawn. This practice has the advantage of retarding the decline in the production of individual wells and considerably increasing the ultimate yield. It also may bring about the
conservation of gas that otherwise would be wasted, and the disposal of brines that otherwise might
pollute surface and near-surface potable waters.
In older fields it was not the usual practice to maintain the reservoir pressure, and it is now necessary to obtain petroleum from these fields by means of secondary recovery projects. Thus, several
methods have been developed to obtain oil from reservoirs where previous economic policies dictated that ordinary production systems were no longer viable.
Considerable experimentation has been carried on in the use of different types of input gas.
Examples are wet casinghead gas, enriched gas, liquefied petroleum gas (LPG), such as butane and
propane, high-pressure gas, and even nitrogen. High-pressure gas not only pushes oil through the
Exploration, Recovery, and Transportation
into the well on a string of 6 in. (inner diameter) steel rods known as sucker rods. The up-and-down
movement of the sucker rods forces the oil up the tubing to the surface. A walking beam powered
by a nearby engine may supply this vertical movement, or it may be brought about through the use
of a pump jack, which is connected to a central power source by means of pull rods. Electrically
powered centrifugal pumps and submersible pumps (both pump and motor are in the well at the
bottom of the tubing) have proven their production capabilities in numerous applications.
There are also secondary oil recovery operations that involve the injection of water or gas into
the reservoir. When water is used the process is called a waterflood; with gas, a gasflood. Separate
wells are usually used for injection and production. The injected fluids maintain reservoir pressure
or repressure the reservoir after primary depletion and displace a portion of the remaining crude oil
to production wells. In fact, the first method recommended for improving the recovery of oil was
probably the reinjection of natural gas, and there are indications that gas injection was utilized for
this purpose before 1900 (Craft and Hawkins, 1959; Frick, 1962). These early practices were implemented to increase the immediate productivity and are therefore classified as pressure maintenance
projects. Recent gas injection techniques have been devised to increase the ultimate recovery, thus
qualifying as secondary recovery projects.
In secondary recovery, the injected fluid must dislodge the oil and propel it toward the production wells. Reservoir energy must also be increased to displace the oil. Using techniques such as gas
and water injection, there is no change in the state of oil. Similarly, there is no change in the state of
the oil during miscible fluid displacement technologies. The analogy that might be used is that of a
swimmer (in water) in which there is no change to the natural state of the human body.
Thus the success of secondary recovery processes depends on the mechanism by which the
injected fluid displaces the oil (displacement efficiency) and on the volume of the reservoir that
the injected fluid enters (conformance or sweep efficiency). In most proposed secondary projects,
water does both these things more effectively than gas. It must be decided if the use of gas offers
any economic advantages because of availability and relative ease of injection. In reservoirs with
high permeability and high vertical span, the injection of gas may result in high recovery factors
as a result of gravity segregation, as described in a later section. However, if the reservoir lacks
either adequate vertical permeability or the possibility for gravity segregation, a frontal drive
similar to that used for water injection can be used (dispersed gas injection). Thus, dispersed gas
injection is anticipated to be more effective in reservoirs that are relatively thin and have little dip.
Injection into the top of the formation (or into the gas cap) is more successful in reservoirs with
higher vertical permeability (200 md or more) and enough vertical relief to allow the gas cap to
displace the oil downward.
Vaporization is another recovery mechanism used to inject gas into oil reservoirs. A portion of
the oil affected by the dry injection gas is vaporized into the oil and transported to the production
wells in the vapor phase. In some instances this mechanism has been responsible for a substantial
amount of the secondary oil produced.
During the withdrawal of fluids from a well, it is usual practice to maintain pressures in the
reservoir at or near the original levels by pumping either gas or water into the reservoir as the
hydrocarbons are withdrawn. This practice has the advantage of retarding the decline in the production of individual wells and considerably increasing the ultimate yield. It also may bring about the
conservation of gas that otherwise would be wasted, and the disposal of brines that otherwise might
pollute surface and near-surface potable waters.
In older fields it was not the usual practice to maintain the reservoir pressure, and it is now necessary to obtain petroleum from these fields by means of secondary recovery projects. Thus, several
methods have been developed to obtain oil from reservoirs where previous economic policies dictated that ordinary production systems were no longer viable.
Considerable experimentation has been carried on in the use of different types of input gas.
Examples are wet casinghead gas, enriched gas, liquefied petroleum gas (LPG), such as butane and
propane, high-pressure gas, and even nitrogen. High-pressure gas not only pushes oil through the