GAS LIFT METHODS USED FOR CRUDE OIL EXTRACTION
INTRODUCTION
The paramount aim of every oil and gas operator is to minimize both capital and operating costs
and more importantly, maximize cumulative oil production in the most cost-effective manner for
the entire field. This is to say that a true production optimization requires an operator to take a
logical look at the field’s production systems from the subsurface to surface facilities. Therefore,
when an oil well fails to flow naturally, it requires an assisted lifting system. Gas lift system is
one of the few artificial lift methods used to start up a well and/or increase the producing life of
oil and gas wells. The principle of Gas lift is by lowering the hydrostatic pressure inside the
production tubing through the injection of lighter fluid into the annulus, It will reduce the density
of the fluids in the tubing, and the bubbles have a scrubbing action on the liquids. Both factors
act to lowering the flowing bottom-hole pressure (BHP) at the bottom of the tubing.
There are four categories of wells in which a gas lift can be considered:
High productivity index (PI), high bottom-hole pressure wells.
High productivity index (PI), low bottom-hole pressure wells.
Low productivity index (PI), high bottom-hole pressure wells.
Low productivity index (PI), low bottom-hole pressure wells.
Gas lift technology has been widely used in the oil fields that produce sandy and gassy oils. It is
also effective in deviated holes, applicable to offshore operations.
GAS LIFT SYSYTEM
This is accomplished by one of the two following methods,
Continuous-flow gas lift
In continuous-flow gas lift , the formation gas is supplemented with additional high-
pressure gas from an outside source. Gas is injected continuously into the production conduit at a
maximum depth that depends upon the injection-gas pressure and well depth. The injection gas
mixes with the produced well fluid and decreases the density and, subsequently, the flowing
pressure gradient of the mixture from the point of gas injection to surface. The decreased flowing
pressure gradient reduces the flowing bottom-hole pressure below the static bottom-hole pressure
thereby creating a pressure differential that allows the fluid to flow into the wellbore. It is an
excellent application for offshore formations that have a strong water drive, or in water flood
reservoirs with good productivity index and high gas/oil ratios. This method is recommended for
high volume and high static bottom-hole pressure wells in which major pumping problems could
occur with other artificial lift methods. Continuous-flow gas lift imposes a relatively high
backpressure on the reservoir compared with pumping methods; therefore, production rates are
reduced. Also, power efficiency is not good compared with some artificial lift methods, and poor
efficiency significantly increases both initial capital cost for compression and operating energy
costs.
Advantages:
Gas lift permits the concurrent use of wire-line equipment, and such down-hole equipment is
easily and economically serviced. This feature allows for routine repairs through the tubing.
Gas lift is flexible. A wide range of volumes and lift depths can be achieved with essentially the
same well equipment. In some cases, switching to annular flow also can be easily accomplished
to handle exceedingly high volumes.
A central gas-lift system easily can be used to service many wells or operate an entire field.
Centralization usually lowers total capital cost and permits easier well control and testing.
Disadvantages:
Relatively high backpressure may seriously restrict production in continuous gas lift. This
problem becomes more significant with increasing depths and declining static bottom-hole
pressures.
Operation and maintenance of compressors can be expensive. Skilled operator and good
compressor mechanics are required for reliable operation.
Adequate gas supply is needed throughout life of project. If the field runs out of gas, or if gas
becomes too expensive, it may be necessary to switch to another artificial lift method. In
addition, there must be enough gas for easy startups.
Intermittent-flow gas lift
Intermittent flow is the periodic displacement of liquid from the tubing by the injection
of high-pressure gas. This action is similar, when a bullet is fired from a gun. The liquid slug that
has accumulated in the tubing represent the bullet. When the trigger is pulled (gas lift valves
opens), high-pressure injection gas enters the chamber (tubing) and rapidly expands. The action
forces the liquid slug from the tubing in the same way that expanding gas forces the bullet from
the gun. This method typically is used on wells that produce low volumes of fluid (approx < 150
to 200 B/D), although some systems produce up to 500 B/D. wells in which intermittent lift is
recommended normally have the characteristics of high productivity index (PI) and low bottom-
hole pressure (BHP) or low productivity index with bottom-hole pressure. It can be used to
replace continuous gas lift on wells that have depleted to low rates or used when gas wells have
depleted to low rates and are hindered by liquid loading.
Advantages:
Intermittent gas lift typically has a significantly lower producing BHP than continuous gas lift
methods.
It has the ability to handle low volumes of fluid with relatively high production BHP’s
Disadvantages:
Intermittent gas lift is limited to low volume wells.
The average producing of a conventional intermittent lift system is relatively high when
compared with rod pumping; however , the producing BHP can be reduced by the use of
chambers.
The power efficiency is low. Typically more gas is used per barrel of produced fluid than with
constant flow of gas lift.
Intermittent gas lift typically requires frequent adjustments. The least operator must alter the
injection rate and time period routinely to increase the production and keep the lift gas
requirement relatively low.
CASE STUDIES
The system has been tested extensively in all available casing sizes for many con- figurations and
operating environments. Case studies from actual field applications provide some details of the
operating environment, system configuration and general results.
In one case study, the system was used on a gas well in Southeast Kilgore, Tx., with a TD of
10,600 feet and where the perforated zone extended from 9,636 to 10,600 feet. The well had
previously been on plunger lift and soap injection, and neither improved production.
The new system was run in 41/2-inch casing with 23/8-inch tubing above the packer and 11/4-
inch tubing with 11/4-inch internally-mounted mandrels below the 41/2-inch bypass packer,
which was set at 9,598 feet. Prior to injecting with the new system, daily production rates were 40
barrels of water and 43 MMcf of gas. Current production rates since injecting with the new system
show a 50 percent in- crease in water (to 60 bbl/d ), 1.5 bbl/d of oil, and a five-fold increase in gas
production (to 225 net MMcf/d), with an injection rate of 200 MMcf/d. In another application
(Figure 3), the system was installed in a gas well in Wyoming with a TD of 13,340 feet and a
1,002-foot perforated zone (from 12,338 to 13,340 feet). The well had previously been on
conventional gas lift with no production improvement. Again, because of its unique configuration,
the system can inject gas across long perforated intervals deep into the well, where liquid loading
problems occur.
The new system was run in 7-inch casing with 27/8-inch tubing above the pack- er and 23/8-inch
tubing with 23/8-inch internally-mounted mandrels below the 7-inch packer, which was set a
12,090 feet. Previous production rates were 79 bbl/d of water and 146 MMcf/d of gas. Since
injecting with the new system, production rates have doubled to 159 bbl/d of water and 367 net
MMcf/day of gas with an injection rate of 300 MMcf/d.
