Plunger Lift System Without Planned Atmospheric Venting

Liquid accumulation in mature production gas wells can lead to reduced pressure and gas production from affected wells. Installing a plunger lift system is an effective method for removing these liquids and restoring gas production. Plunger lift systems without planned atmospheric venting have the additional benefit of maintaining reservoir energy and well production while virtually eliminating the methane emissions associated with traditional well blowdowns used to remove the accumulated liquid. A plunger lift uses gas pressure and volume buildup in the well casing and near-wellbore reservoir to push a column of accumulated fluid out of the well tubing with a somewhat loose-fitting plug.

Installing a plunger lift system is an effective method for removing liquids from natural gas wells. Plunger lift systems push liquids out of the well tubing against the sales line back pressure without atmospheric venting. This has the additional benefit of increasing production while virtually eliminating methane emissions associated with liquids unloading.  

The operation of a plunger lift system relies on the natural buildup of pressure in the casing of a gas well during the time that the well is shut-in (i.e., not producing). The well shut-in pressure must be sufficiently higher than the sales-line pressure to lift the plunger and the liquid load to the surface. Figure 1 presents a typical plunger lift system. A typical plunger lift cycle starts with shutting a valve to the sales line (the motor valve), dropping the plunger and allowing sufficient time for it to fall to the bottom and then for the well casing and near-wellbore reservoir to build pressure and volume. The cycle continues by opening the motor valve, which allows the volume of high-pressure gas in the casing and near-wellbore reservoir to push the plunger and the liquid load to the surface. The plunger is caught at the top of the well and held while liquids are being displaced until production flow resumes normal pipeline back pressure, at which point the plunger is dropped back to the bottom of the well tubing.  

In a plunger lift system, the motor valve may be manually controlled or automatically controlled by a timer or microprocessor. The mechanism controlled by a microprocessor, which is referred to as “smart automation,” uses information, such as well pressures, a stored history of cycle times, other physical well parameters, and an algorithm to optimize the plunger cycle timing with variations in reservoir pressure, sales line pressure, and liquid accumulation rate. The valves and controller of the plunger lift system are typically solar powered. When the reservoir shut-in pressure becomes insufficient to lift a liquid load, the plunger control system can be reconfigured to open and close a vent to the atmosphere before the sales line is re-opened. An automated plunger lift significantly reduces methane emissions compared to blowing down the well. 

Regardless of activation system (i.e., manual, fixed time cycle, preset pressure differential, dynamic smart algorithm), variability in reservoir performance and sales line back pressure can result in launching the plunger cycle too early or too late. Launching too early, with too little liquid load (“underloading”), can result in the plunger travelling too fast and damaging the wellhead catcher. Launching too late, with too much liquid load (“overloading”), can result in not being able to lift the plunger. Both conditions can require venting gas to the atmosphere to correct. Using a “smart automation” system for control of a plunger lift installation can better manage the operation of a plunger lift, deliver incremental gas production, and virtually eliminate venting. Automated control systems optimize plunger lift and well unloading operations to prevent overloading and underloading, therefore reducing or eliminating well venting. 

Smart automation control systems combine customized control software with standard well control hardware, such as remote terminal units and programmable logic controllers (PLCs) to cycle the plunger system and lift fluids out of the tubing. The artificial intelligence component of a smart automation system monitors the wellhead casing, tubing, sales line pressures, and plunger run frequency and allows the PLC to “learn” a well’s specific performance characteristics (e.g., flow rate and plunger travel timing) and build an inflow performance relationship curve for the well. The frequency and duration of the plunger cycle is then modified to optimize well performance. Data analysis combined with wellhead control technology is the key to an effective gas well smart automation system. A smart automation system, in the wellsite PLC, stores historical well production data allowing the program to optimize well production by monitoring and analyzing wellhead instrument data. The control system can relay wellhead instrument data to a central computer, track venting times, and report well problems and high-venting wells, all of which allow custom management of field production.  

Automated controllers and sensors at the wellhead monitor well parameters and adjust plunger cycling. These can be operated on low-voltage, solar batteries. Technologies such as smart automation, online data management and satellite communications can also allow operators to control plunger lift systems remotely, without regular field visits. Enabling remote management of these systems allows operators to visit only the wells that need attention, which increases efficiency and reduces cost.

Figure 1. Plunger Lift System.

Plunger lifts are applicable to gas wells that experience liquid loading and have sufficient reservoir shut-in pressure to lift the liquids and plunger to the surface. This technology may be employed on vertical gas wells, slant-drilled gas wells, and on the vertical or lightly deviated sections of horizontal gas wells. Vendors often will supply models and/or written materials designed to help operators ascertain whether a particular well would benefit from the installation of a plunger lift system. The following well characteristics are good indicators of plunger lift applicability: 

• Wells experiencing liquid loading and fluid removal techniques are necessary to maintain production 
• Wells producing at least 400 scf of gas per barrel of fluid for every 1,000 feet of depth 
• Well has shut-in wellhead pressure that is 1.5 times the maximum sales line pressure 
• Well builds pressure and volume in the annulus and near-wellbore reservoir when shut-in 
• Well has relatively straight tubing that can freely pass the plunger 
• Well does not have scale or paraffin buildup which precludes plunger runs (note that plungers with scale brushes or paraffin cutters are available) 

Methane emission reductions can be determined by taking the difference in emissions from the source before and after the specific mitigation action was applied. While using actual measurements may provide a more accurate representation of emissions/reductions from individual equipment at a given time, methane emissions can also be reasonably calculated by using emission factors. When installing a plunger lift for liquids unloading, this means calculating emissions from liquids unloading without a plunger lift and subtracting emissions from liquids unloading with a plunger lift. Emission reductions from plunger lifts can be estimated using emission factors representing liquids unloading scenarios with and without plunger lifts from the Natural Gas Systems section of the Inventory of U.S. Greenhouse Gas Emissions and Sinks (“Greenhouse Gas Inventory”, or “GHGI”). These emission factors are based upon reported subpart W data and are uniquely calculated each year and highly variable from year to year. 

ER = W × (EF_NP – EF_P)  

Where: 

ER = Emissions reduction estimate (kg CH₄/yr) 

W = Number of wells (wells/yr) 

EF_NP = Emission factor – liquids unloading without plunger lifts (kg CH4/wells) 

EF_P = Emission factor – liquids unloading with plunger lifts (kg CH₄/wells) 

Assumptions/Constants: 

• Use the most current “liquids unloading without plunger lifts” and “liquids unloading with plunger lifts” emission factors. Emission factors are generally developed to be representative of long-term averages for all applicable emission sources. EPA updates the emission factors from the Natural Gas Systems section of the Inventory of U.S. Greenhouse Gas Emissions and Sinks (“Greenhouse Gas Inventory”, or “GHGI”) every year, so specific emission factors may change. To find the current emission factor, navigate to the GHGI website for Natural Gas and Petroleum Systems and click on the page for the most recent inventory. On that page, you will find links for Annex 3.5 (Methodology for Estimating CH₄, CO₂, and N₂O Emissions for Petroleum Systems) and Annex 3.6 (Methodology for Estimating CH₄, CO₂, and N₂O Emissions for Natural Gas Systems). Methane emission factors can be found in Table 3.5-3 (Petroleum Systems) and Table 3.6-2 (Natural Gas Systems). 

The calculation methodology in this emissions reduction section is based upon current information and regulations (as of August 1, 2023). EPA will periodically review and update the methodology as needed.

In addition to reducing methane emissions, installing a plunger lift system may: 

• Increase revenue: Gas production may increase and make operating the well more cost-effective. 
• Extend well life: Wells that experience scale or paraffin build-up can operate longer between well workovers by using a plunger lift designed for scale or paraffin removal.  
• Increase liquids production: Wells that move water continuously out of the well bore have the potential to produce more condensate and oil. 

Estis Compressions. (2022, January 4). How to compare artificial lift options for unconventional oil production. https://www.estiscompression.com/learning-center/how-to-compare-artificial-lift-options-for-unconventional-oil-production

Hernández, A. (2016). Fundamentals of gas lift engineering: Well design and troubleshooting. Gulf Professional Publishing. https://doi.org/10.1016/C2015-0-01589-1

Lea, J. F., Jr., & Rowlan, L. (2019). Gas well deliquifaction, Third Edition. Gulf Professional Publishing.  

https://doi.org/10.1016/C2017-0-04099-5