When Plunger Lift? (Jan 7, 2016)
In the last article, we reviewed why a well might benefit from the use of plunger lift (https://www.shaletec.com/faq/). In this article, we’ll look at when plunger lift may result in higher production and/or lower lifting cost. As stated in the prior article, plunger lift uses the wells own energy to remove liquids. The plunger acts as an interface between the gas pressure below the plunger and the liquid column above the plunger. Reservoir gas enters the end of tubing, exerting pressure on the bottom of the plunger. When the gas pressure and volume is sufficient, the plunger, powered by the reservoir gas, lifts the column of liquid to the surface.
Artificial lift should be considered for a well before liquid impedes the flow of gas to the surface, or for oil wells when sufficient gas is present to assist in moving the oil to the surface. Understanding the basic gas flow transition states will aide in deciding when to consider artificial lift.
Typically, a gas well’s flow will progress as shown below:
During mist flow, gas flow is high enough to entrain liquid in the gas stream and move the liquid to the surface. There may also be a liquid film lining the walls of the tubing during this phase. As the flow rate declines, some liquid will fall and collect in the bottom of the well. Gas bubbles through the liquid column at the bottom of the well, while still creating a constant, though reduced, flow at the surface. Over time, the height of the liquid column at the bottom of the well increases. The gas will then tend to push slugs of liquid to the surface. These slugs can be heard moving through the wellhead, followed by streams of gas. If this condition is allowed to progress, the well will eventually build a substantial column of liquid in the bottom of the well, stopping the flow of gas to the surface. In addition to physically blocking the tubing, liquid also creates downward pressure on the perforations, and thus reservoir. Backpressure reduces the volume of gas and liquid flowing from the reservoir into the well bore.
Knowing that liquid will eventually impede the flow of gas to the surface, the question becomes “When will artificial lift increase production or reduce cost for a gas well”? If we know that answer, artificial lift can be installed prior to that occurrence. Some predictive helpful tools include:
- Natural decline curves
- Critical flow rate
- Liquid level measurement
- Echometer well analyzer
- PCSFerguson smart plunger
- Pressure / temperature downhole surveys
Natural decline curves depict the natural production decline (without liquid loading) of the well over time. The critical flow rate is defined as the flow rate above which all liquid is carried to the surface. Wells which produce liquid and are flowing below the critical flow rate allow some liquid to fall back into the well. Critical flow rate values were originally determined using empirical data from vertical wells, and use the flowing pressure to identify the associated required flow rate. Since we’re most interested in keeping liquid from collecting in the bottom of the well, the bottom hole flowing pressure is usually best used to determine the well’s critical flow rate.
SPE 120625 “Guidelines for the Proper Application of Critical Velocity Calculations” by Sutton, Cox, Lea and Rowand is an informative paper on this topic.
Once the critical flow rate for a reservoir is known, it can be overlaid onto the well’s natural decline curve to predict when liquid will start collecting in the well. Installing artificial lift prior to this event will help maintain maximum production.
For wells suspected of already having liquid in the well bore, a pressure survey using wireline, Echometer acoustical analysis or PCSFerguson’s Smart Plunger can help pinpoint the height of the liquid column. Echometer’s well analyzer discharges a pressure wave into the well bore (tubing or casing). When the pressure wave hits the liquid interface, the pressure signal is reflected back to the surface. By knowing the velocity at which sound (pressure waves) travel, Echometer’s well analyzer calculates the height of the fluid column. PCSFerguson’s Smart Plunger is a device that can be set in the well bore, or cycled like a plunger. The device collects temperature and pressure. When it is removed from the well, the device is connected to a PC and the data downloaded for analysis.
Because critical flow rate was developed for the vertical section of wells, it does not reflect the flow rate required to move liquid in the horizontal section. Dr. Lea, in “Gas Well Deliquification” estimates a flow rate of around 14 ft/s is required to sweep liquid from the low lying pipe sections in the horizontal portion of a well. Whether due to the liquid in the lateral leg, or the liquid lining the vertical walls of the tubing during mist flow, some operators are realizing substantial production improvements by installing plunger lift in wells flowing significantly greater than 1 mmcf/d! Using decline curves and Turner’s critical flow rate is a good starting point for determining when to install artificial lift, yet additional experimentation is encouraged – especially with high flow rate horizontal wells.
There are a number of factors to consider prior to concluding a well is a candidate for plunger lift. Many of these factors are referenced in my last article “Why Plunger Lift” (See www.ShaleTec.com/faq/). Some of the stated limitations and calculations are based on the industry’s experience with vertical, liquid loaded wells. Today’s precision electronic controllers, continuous run plungers, multi-stage tools and gas assisted plunger lift have tremendously increased the number of existing wells that will benefit from the use of plunger lift.
On the low flow rate end of the spectrum, wells which are swabbed or intermittent will often benefit from plunger lift. When these wells stop producing due to significant liquid in the tubing, the well may be swabbed, or manually shut-in until sufficient pressure builds to push the liquid to the surface. For wells using foaming agents, plunger lift (no recurring monthly cost) often provides a reduced cost solution. Often, a brush plunger or light weight hollow bar stock plunger performs best in these type wells. When evaluating the operational costs, the wells downtime (non-productive time) and lease operator’s time should be considered.
Gas lift is a method in which gas is injected into the well’s annulus to lift the liquid in the well to the surface. Gas lift is often deployed to assist in the removal of large volumes of liquid from wells. As the liquid is removed, many of these wells can be successfully (and cost effectively) converted to plunger lift. One study found the average lifting cost using gas lift was $ 1.17/mcf vs only $ 0.50/mcf for plunger lift with telemetry. Where possible, plunger lift often results in a reduced operational cost solution to remove liquid from wells.
On the high flow rate end of the spectrum, horizontal wells flowing above 1 mmcf/d routinely benefit from plunger lift installations. Some of these wells produce over 200 bbls of liquid per day! A few years ago, wells in this category would have never been considered for plunger lift. Yet, today’s continuous run plungers, requiring little to no shut-in time, have changed the game! When a plunger can make 60 cycles or more per day, lifting a small amount of liquid on each cycle, the well bore remains open for gas to flow unobstructed to the surface.
Knowledge is the key to increasing production from plunger lift capable wells. If your team could benefit from a deeper understanding of plunger lift, Shale Tec LLC is offering 2-Day Plunger Lift Courses throughout the US in 2016.
The next classes are scheduled for Shreveport, La (Jan 25, 26) and Natchitoches, La (Jan 28, 29).
The course includes the following topics:
And, consider joining the Linkedin Group “Plunger Lifted Gas Wells”
The above article was written by David Cosby P.E. of Shale Tec LLC
Copyrighted January 2016