Traditional gas lift delivers only limited success in long interval environments. Newer techniques overcome shortcomings, but a single tool does not solve every problem.

Above the packer, method is similar to traditional gas lift (shown in red). Landed directly below the packer, a dead string with a perforated sub and a bull plug is installed (shown in blue). Fluid is lifted to the surface via the operating valve directly above the packer. (Images courtesy of International Lift Systems)

Opportunities exist today to combine artificial lift methods that — in today’s economic landscape — can cost-effectively optimize
production from gas wells that would otherwise be delivering diminishing returns. Most recently, a variety of innovative techniques using gas lift have
been applied successfully to wells with long perforated intervals.

In the past, gas lift has been primarily used for offshore applications. However, land applications are occurring with increasing rapidity. It now pays to make the investments necessary to re-inject gas into a well to improve recovery, rather than use some other methods of artificial lift.

In particular, wells with long perforated intervals or multiple zones, producing below critical rate and with high fluid rates, can today be addressed choosing one of several gas-lift techniques selected on the basis of application.

Traditional gas lift delivers only limited success in long interval environments. Typically, a reservoir does not have enough energy to lift fluid from the bottom perforations to the packer. For this and other reasons, the overall efficiency of the system is poor.

These shortcomings may stem from any of several reasons, including the following:
• Gas injection with no packer is generally not preferred;
• Velocity strings are not effective due to fluid volumes; and
• Cap strings have limited results due to fluid volume and reduced formation gas.
On the other hand, newer techniques are able to overcome these shortcomings. These include the following:
• Retrievable cross-flow assembly. Allowing for a fluid path between the casing annulus and tail allows for injection of gas below a packer with fluid and gas flow back into the tubing string through the assembly;
• Dead-string with gas lift. Tubing
below the packer with a ported
sub to improve velocities across the perforations;
• Annular flow with gas lift. Concentric gas lift mandrels with internally mounted valves are used with injection down the tubing and production up the annulus; and
• Dip tube with gas lift. For horizontal applications, injection is down the casing to a special hanger mandrel above the tubing, with gas then injected through the valve into a
dip tube landed below the packer.

Since most gas production here in the US is of lower permeability, or considered to be “tight gas,” it is important to consider all possibilities in maximizing production. Because a given method might have worked well on a few select wells or in a different area, there has been a tendency to focus on that single method of artificial lift. It is important to note that one tool does not solve all problems.

In fact, over the past few years, gas well optimization methods have become a serious topic of conversation. A number of the major E&P companies have assembled teams for the express purpose of surveying multiple wells within a given field to pinpoint the most suitable lift technique for each well.

ILS is focused on this approach and has put these techniques to good use in fields in Texas and Louisiana, where trends for combining multiple zones have led to longer perforated intervals and a need to optimize gas flow.

Retrievable cross-flow assembly

This technique is applicable for wells that are producing moderately high fluid rates (less than 400 b/d depending on the tubing size). To be effective, gas injection must occur as deep as possible below the packer. Possible disadvantages are that solids production can be a problem; slick-line operations cannot be performed below the packer; and higher bottomhole pressure is required.

On the other hand, there are advantages. This approach:
• Allows for injection below a packer to effectively unload the perforation interval;
• Ensures gas injection pressure is kept off the formation;
• Achieves the lowest flowing pressure possible with the packer in place;
• Provides a lower critical rate due to smaller flow area below the packer; and
• Allows chemicals and surfactants to be introduced along with the injection gas, either through surface injection or cap string.

Gas is injected down the tubing to a valve directly tied into the cross-flow assembly. Gas is then directed through the port and into the tubing where internally mounted
valves allow injection into the annulus as deep as possible. The tubing below the cross-flow assembly also acts as a flow-area reduction string (dead string), increasing the gas velocities below the packer. The combination of injection gas and reduced flow area allows for maximum productivity. Fluid and gas are then directed into ports on the outside of the assembly back into the tubing above the packer and to the surface.

In this scenario, the cross-flow assembly mates to the top of a standard retrievable packer such as an AS1-X packer. Packer setting and retrieving are not altered by the addition of the cross-flow assembly.

Dead string with gas lift

This technique is suitable for wells producing higher fluid rates, where it is not possible to effectively inject gas deeper than the packer or the top of the perforated interval.
Possible disadvantages of this technique include the following:
• Solids production can be a problem;
• Blockage/bridging around the dead string can occur;
• It’s not possible to perform slick-line operations unless the tubing string is pulled, although a retrievable plug could be used; and
• An incorrect dead-string design could cause a downhole flow restriction.
On the other hand, advantages include the following:
• Effective unloading of a long interval is achieved via improved velocities;
• The packer ensures injection pressure is kept off the formation;
• A lower flowing bottomhole pressure is achieved; and
• Chemicals or surfactants can be introduced into the system through the gas-lift valves or a cap string.

Above the packer, this method is similar to that associated with traditional gas lift (Figure 1). Below the packer, a dead string with a perforated sub — landed directly below the packer — and a bull plug is installed. The dead-string design must be based on achieving the most effective flow area and least amount of friction pressure.

The resulting reduced flow area below the packer increases velocities and lowers the critical-rate requirement. Fluid is directed above the packer and lifted to the surface via the operating valve directly above the packer.

Annular flow with IM gas lift

This option is suitable for wells producing moderate fluid rates where it is not possible to effectively unload using a plunger system or a cap string. It is best applied where the bottom zone or zones are known to be strong contributors to overall flow.

One of the disadvantages of this approach is that it is not possible to perform slick-line operations unless the tubing string is pulled. In addition, it is very important to determine flow area requirements properly, as friction pressure could hinder production (similar to a dead-string design). Finally, the technique may not be viable if CO2 or H2S are present or a corrosive environment exists and exposure to the casing is not recommended.

However, there are substantial advantages too:
• Effective unloading of the entire interval is possible;
• Injection pressure is contained in the tubing and kept off the formation;
• The lowest flowing bottomhole pressure is achieved based on the fact that the fluid is being cleared as deep as possible;
• Chemicals and surfactants can be introduced into the system through the gas-lift valves;
• Solids aren’t a problem; and
• Unloading periods are shorter since the tubing is dry – only the casing is filled with fluid.

In this approach, concentric mandrels with internally mounted valves are used with injection down the tubing. In this way, injection gas can be introduced as low as possible in the perforated interval, with flow up the annulus. The tubing also is used as a reduction string, improving velocities in the annulus and helping reduce the critical rate requirement. Note that the system does not require as many valves as are required with other approaches — the tubing string is dry to begin with — and no unloading valves are necessary.

Dip tube gas injection

This technique is suitable for horizontal wells that are producing too much fluid for a plunger system to be effective, i.e., the plunger cannot get deep enough to lift fluid. The main design parameters for the system are fluid rate and reservoir pressure.

One of the major disadvantages to this system is that it is not possible to perform slick-line operations unless the tubing string is pulled. Solids can be a problem, due to washing of the standing valve or plugging of the slotted pup. The system is also fluid-rate restricted, so it is best suited for wells producing less than 200 bbl/MMcf/d.

Advantages to the system are that it creates a more consistent inflow from the reservoir and effectively reduces flowing bottomhole pressure. Both cases result in increased production. This is a contained system below the packer; so injection gas is kept off the formation. And the system is able to operate at lower than normal reservoir pressures (minimum of 400 psi).

Injection flows down the casing to a special hanger mandrel above the tubing (Figure 3). Gas is then injected through the valve into a smaller dip tube, landed below the packer. The production tubing extends below the packer into the horizontal section (typically 700 ft MD). Section length actually is dependent on the deviation of the horizontal section, and ideally extends into the 90° section where fluid is suspected to be accumulating. The dip-tube string is typically 1 in. to 11?4 in. in-line pipe. By introducing gas injection deeper into the leg, the amount of injection is less than it would be if it were done above the packer only.

The dip tube is equipped with a standing valve and slotted nipple or pup joint. The standing valve allows fluid to enter into the tubing without surging back. Dip tube injection assists the fluid up past the packer and into the tubing string to the surface. The tubing below the packer also assists in bringing better velocity deeper into the well.

Final words

Success at increasing the performance of gas wells using artificial lift methods begins with accurate collection of well data, including reservoir and surface
pressures, and production history. With so many options available, improved production and reduced operating costs requires thoughtful first-time selection of the correct artificial lift means. Understanding the parameters for successful application of each artificial lift method ensures substantial benefits.