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Gas lift has become the favored artificial lift method for unconventional wells in the Permian Basin. It provides reasonable tolerance to gas production and surging trends while maintaining flexibility for an unconventional well’s rapid production decline. These wells are produced from a fixed stimulated reservoir volume (SRV) where the fractures created close and affect production.
The SRV often maintains gas and water inflow that result in near flow conditions throughout the economic life of the well, so current directives to shrink costs lead many designers to reduce the number of unloading valves in a gas lift design. While this concept is valid, rapidly advancing technology can stretch the limits of well spacing, proppants, chemicals, parent-child relationships and, unfortunately, frac hits and wellbore damage that affect near flow conditions and compromises production.
A conservative approach to gas lift design is the design line method, based on a projection of inflow conditions in later stages of the well. This design can continue to produce the well when the unexpected occurs and/or throughout the life of the well.
The Design Line method includes Nodal analysis of flowing conditions along with established engineering relationships while using a time-tested method to predict inflow as SRV pressure declines. The result may be to add one or two more unloading valves, using an algorithm to locate valves to bottom. This design should meet the well’s future needs, which may eventually require plunger lift assistance.
A key requirement is to use the best possible gas lift valves because they are not all created equal. The cost difference of installing a few extra good gas lift valves is minor compared to the expense of pulling them out when they fail, or when the design fails to produce at optimum rates. These extra valves ensure unloading with the surface gas injection pressure as the SRV declines and they allow for any unexpected SRV occurrences.
Methodology of using a design line in designing gas lift
Design Line is constructed within the boundaries formed by the tubing pressure gradient (from nodal analysis), the kickoff gas pressure gradient (from gas specific gravity and surface pressure), and the kill fluid gradient (from the workover fluid in the casing annulus and the tubing). Creating a conservative design line with higher pressures than the flowing gradients from the Nodal analysis and projecting these conditions to predicted “end of economic life” conditions described above provides a gas lift completion that serves the lift needs of the well throughout its life cycle. It also may prove sufficient flexibility to react to erratic behavior as reservoir and tubing pressures decline from early conditions in cases where valves unload and operate at variable depths. Other unexpected risks include frac hits, parent-child results, or wellbore damage.
Figure 1 shows the conventional gas lift design of an Upton County well in which valves are spaced with the tubing pressure curve.
In Figure 2, gas lift valves are spaced along with the design line. The slope of this design line is based on the solution point from the pressure-traverse curve (the well’s productivity).
As shown in Figure 3, by including an engineered projection of the future reduced downhill pressures, the design is prepared to meet lift requirements in the latter stages of the well’s life.
The projection of future pressures is based on current inflow influenced by a factor developed and proven through years of experience. One its major advantages is a structured approach to valve pressure settings based on dynamic well conditions. With the growing trend toward closer well spacing, this practice also increases the likelihood of continued success when unexpected frac hits or parent-child reactions occur, as well as any incidence of further damage.
The normal objective of gas lift designs is to inject from the lowest valve. This allow the system to create the largest drawdown and produce the most fluid with the available surface injection pressure. The valves on top of the injection valve (unloading valves) helped unload the fluid, so injection would occur at the lower valve.
A close study of SRV characteristics reveals that gas production tends to increase, while water inflow stays the same or decreases as the SRV pressure declines. This allows the well to continue flowing as it approaches the economic limits of the SRV life cycle with just a little help from gas lift. Applying this knowledge in the quest to increase ROI leads to a reduction in the number of unloading valves. Designs are based on the expected tubing flowing gradient.
Unfortunately, frac hits, parent-child conditions, and wellbore damage effects can create changes to the expected conditions. They have also mean traditional designs may be unable to inject to the lowest possible valve. These types of production pressure design lines are sometimes used with a choke upstream of a seat of the valves. These designs probably include more mandrels than necessary, but the designs are also usually more flexible (which is especially helpful if necessary design data is missing or unreliable).
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