Lessons Learned 

from Natural Gas STAR Partners 

Installing Plunger Lift Systems In 

Gas Wells 

Executive Summary 

In mature gas wells, the accumulation of fluids in the well 

can impede and sometimes halt gas production. Gas flow 

is maintained by removing accumulated fluids through the 

use of a beam pump or remedial treatments, such as 

swabbing, soaping, or venting the well to atmospheric

pressure (referred to as “blowing down” the well). Fluid 

removal operations, particularly well blowdowns, may 

result in substantial methane emissions to the 

atmosphere. 

Installing a plunger lift system is a cost-effective 

alternative for removing liquids. Plunger lift systems have 

the additional benefit of increasing production, as well as

significantly reducing methane emissions associated with 

blowdown operations. A plunger lift uses gas pressure

buildup in a well to lift a column of accumulated fluid out

of the well. The plunger lift system helps to maintain gas

production and may reduce the need for other remedial 

operations. 

Natural Gas STAR Partners report significant economic

benefits and methane emission reductions from installing 

plunger lift systems in gas wells. Companies have 

reported annual gas savings averaging 600 thousand cubic 

feet (Mcf) per well by avoiding blowdowns. In addition, 

increased gas production following plunger lift installation

has yielded total gas benefits of up to 18,250 Mcf per well,

worth an estimated $127,750. Benefits from both 

increased gas production and emissions savings are welland reservoir-specific and will vary considerably. 

Technology Background 

Liquid loading of the wellbore is often a serious problem in 

aging production wells. Operators commonly use beam lift

pumps or remedial techniques, such as venting or “blowing 

down” the well to atmospheric pressure, to remove liquid 

buildup and restore well productivity. These techniques, 

however, result in gas losses. In the case of blowing down

a well, the process must be repeated over time as fluids

reaccumulate, resulting in additional methane emissions. 

Plunger lift systems are a cost-effective alternative to both

beam lifts and well blowdowns and can significantly 

reduce gas losses, eliminate or reduce the frequency of

future well treatments, and improve well productivity. A 

plunger lift system is a form of intermittent gas lift that

uses gas pressure buildup in the casing-tubing annulus to

push a steel plunger, and the column of fluid ahead of it,

up the well tubing to the surface. The plunger serves as a

piston between the liquid and the gas, which minimizes 

liquid fallback, and as a scale and paraffin scraper.

Exhibit 1 depicts a typical plunger lift system. 

The operation of a plunger lift system relies on the natural

buildup of pressure in a gas well during the time that the 

well is shut-in (not producing). The well shut-in pressure

must be sufficiently higher than the sales-line pressure to

lift the plunger and liquid load to the surface. A valve 

mechanism, controlled by a microprocessor, regulates gas

input to the casing and automates the process. The 

controller is normally powered by a solar recharged

battery and can be a simple timer-cycle or have solid state 

Economic and Environmental Benefits 

Method for 

Reducing 

Natural Gas 

Losses 

Potential Gas Savings 

from Increased Gas 

Production and Avoided 

Emissions (Mcf) 

Value of Natural Gas Production and 

Savings ($) Payback (Months) 

$3 per 

Mcf 

$5 per 

Mcf 

$7 per 

Mcf 

$3 per 

Mcf 

$5 per 

Mcf 

$7 per 

Mcf 

Install a 

Plunger Lift 

System 

4,700 - 18,250a per year 

per well 

$14,100 -

$54,750 

per year 

$23,500 -

$91,250 

per year 

$32,900 -

$127,750 

per year 

$2,591 - $10,363 

per year per well 1 - 9 1 - 6 1 - 4 

General Assumptions: 

a Based on results reported by Natural Gas STAR Partners. 

Implementation 

Cost ($) 

1 
 

 

 

 

Installing Plunger Lift Systems In Gas Wells 

(Cont’d) 

Exhibit 1: Plunger Lifts 

memory and programmable functions based on process 

sensors. 

Operation of a typical plunger lift system involves the

following steps: 

1.	 The plunger rests on the bottom hole bumper spring

located at the base of the well. As gas is produced to

the sales line, liquids accumulate in the well-bore, 

creating a gradual increase in backpressure that slows 

gas production. 

2.	 To reverse the decline in gas production, the well is

shut-in at the surface by an automatic controller. This 

causes well pressure to increase as a large volume of 

high pressure gas accumulates in the annulus between

the casing and tubing. Once a sufficient volume of gas 

and pressure is obtained, the plunger and liquid load

are pushed to the surface. 

3.	 As the plunger is lifted to the surface, gas and 

accumulated liquids above the plunger flow through 

the upper and lower outlets. 

4.	 The plunger arrives and is captured in the lubricator,

situated across the upper lubricator outlet. 

5. The gas that has lifted the plunger flows through the 

lower outlet to the sales line. 

6. Once gas flow is stabilized, the automatic controller 

releases the plunger, dropping it back down the tubing. 

7. The cycle repeats. 

New information technology systems have streamlined 

plunger lift monitoring and control. For example,

technologies such as smart automation, online data 

management and satellite communications allow operators 

to control plunger lift systems remotely, without regular 

field visits. Operators visit only the wells that need 

attention, which increases efficiency and reduces cost. For 

more information regarding this technology and other 

artificial lift systems, see the Lessons Learned document 

titled “Options for Removing Accumulated Fluid and 

Improving Flow in Gas Wells”. 

Economic and Environmental Benefits 

The installation of a plunger lift system serves as a costeffective alternative to beam lifts and well blowdown and 

yields significant economic and environmental benefits.

The extent and nature of these benefits depend on the

liquid removal system that the plunger lift is replacing. 

Lower capital cost versus installing beam lift 

equipment. The costs of installing and maintaining 

a plunger lift are generally lower than the cost to 

install and maintain beam lift equipment. 

Lower well maintenance and fewer remedial 

treatments. Overall well maintenance costs are 

reduced because periodic remedial treatments such

as swabbing or well blowdowns are reduced or no 

longer needed with plunger lift systems. 

Continuous production improves gas 

production rates and increases efficiency.

Plunger lift systems can conserve the well’s lifting 

energy and increase gas production. Regular fluid 

2 
 

 

 

 

Installing Plunger Lift Systems In Gas Wells 

(Cont’d) 

removal allows the well to produce gas continuously 

and prevent fluid loading that periodically halts gas 

production or “kills” the well. Often, the continuous 

removal of fluids results in daily gas production rates 

that are higher than the production rates prior to the 

plunger lift installation. 

Reduced paraffin and scale buildup. In wells 

where paraffin or scale buildup is a problem, the

mechanical action of the plunger running up and 

down the tubing may prevent particulate buildup 

inside the tubing. Thus, the need for chemical or 

swabbing treatments may be reduced or eliminated. 

Many different types of plungers are manufactured

with “wobble-washers” to improve their “scraping” 

performance. 

Lower methane emissions. Eliminating repetitive

remedial treatments and well workovers also reduces 

methane emissions. Natural Gas STAR Partners 

have reported annual gas savings averaging 600 Mcf 

per well by avoiding blowdown and an average of 30 

Mcf per year by eliminating workovers. 

Other economic benefits. In calculating the 

economic benefits of plunger lifts, the savings from

avoided emissions are only one of many factors to

consider in the analysis. Additional savings may 

result from the salvage value of surplus production 

equipment and the associated reduction in electricity 

and work over costs. Moreover, wells that move 

water continuously out of the well bore have the 

potential to produce more condensate and oil. 

Decision Process 

Operators should evaluate plunger lifts as an alternative 

to well blowdown and beam lift equipment. The decision to 

install a plunger lift system must be made on a case-bycase basis. Partners can use the following decision process 

as a guide to evaluate the applicability and costeffectiveness of plunger lift systems for their gas

production wells. 

Step 1: Determine the technical feasibility of a 

plunger lift installation. 

Plunger lifts are applicable in gas wells that experience

liquid loading and have sufficient gas volume and excess

shut-in pressure to lift the liquids from the reservoir to the 

surface. Exhibit 2 lists four common well characteristics 

that are good indicators of plunger lift applicability. 

Vendors often will supply written materials designed to 

Four Steps for Evaluating Plunger Lift Systems: 

1. Determine the technical feasibility of a plunger lift installation; 

2. Determine the cost of a plunger lift system; 

3. Estimate the savings of a plunger lift; and 

4. Evaluate the plunger lift’s economics. 

help operators ascertain whether a particular well would

benefit from the installation of a plunger lift system. As 

an example, a well that is 3,000 feet deep, producing to a 

sales line at 100 psig, has a shut-in pressure of 150 psig 

and must be vented to the atmosphere daily to expel and 

average of three barrels per day of water accumulation.

This well has sufficient excess shut-in pressure and would 

have to produce 3,600 scf per day (400 scf/bbl/1000 feet of 

depth times 3000 feet of depth, times 3 barrels of water per

day) to justify use of a plunger lift. 

Well blowdowns and other fluid removal techniques are necessary 

to maintain production. 

Wells must produce at least 400 scf of gas per barrel of fluid per 

1,000 feet of depth. 

Wells with shut-in wellhead pressure that is 1.5 times the sales line 

pressure. 

Wells with scale or paraffin buildup. 

Exhibit 2: Common Requirements 

for Plunger Lift Applications 

Step 2: Determine the cost of a plunger lift system. 

Costs associated with plunger lifts include capital, start-up

and labor expenditures to purchase and install the 

equipment, as well as ongoing costs to operate and 

maintain the system. These costs include: 

Capital, installation, and start-up costs. The 

basic plunger lift installation costs approximately

$1,900 to $7,800. In contrast, installation of surface 

pumping equipment, such as a beam lift, costs 

between $26,000 and $52,000. Plunger lift 

installation costs include installing the piping,

valves, controller and power supply on the wellhead

and setting the down-hole plunger bumper assembly

assuming the well tubing is open and clear. The 

largest variable in the installation cost is running a 

wire-line to gauge the tubing (check for internal 

blockages) and test run a plunger from top to bottom 

(broaching) to assure that the plunger will move 

freely up and down the tubing string. Other start-up

costs can include a well depth survey, swabbing to 

3 
 

Installing Plunger Lift Systems In Gas Wells 

(Cont’d) 

Revenue from Increased Production 

Nelson Price Indexes 

In order to account for inflation in equipment and 

operating & maintenance costs, Nelson-Farrar 

Quarterly Cost Indexes (available in the first issue of 

each quarter in the Oil and Gas Journal) are used to 

update costs in the Lessons Learned documents. 

The “Refinery Operation Index” is used to revise

operating costs while the “Machinery: Oilfield Itemized 

Refining Cost Index” is used to update equipment 

costs. 

To use these indexes in the future, simply look up the 

most current Nelson-Farrar index number, divide by 

the February 2006 Nelson-Farrar index number, and, 

finally multiply by the appropriate costs in the Lessons 

Learned. 

remove well bore fluids, acidizing to remove mineral

scale and clean out perforations, fishing-out debris in 

the well, and other miscellaneous well clean out 

operations. These additional start-up costs can range

from $700 to more than $2,600. 

Operators considering a plunger lift installation 

should note that the system requires continuous 

tubing string with a constant internal diameter in 

good condition. The replacement of the tubing

string, if required, can add several thousands of

dollars more to the cost of installation, depending 

upon the depth of the well. 

Operating costs. Plunger lift maintenance requires

routine inspection of the lubricator and plunger. 

Typically, these items need to be replaced every 6 to 

12 months, at an approximate cost of $700 to $1,300 

per year. Other system components are inspected 

annually. 

Step 3: Estimate the savings of a plunger lift. 

The savings associated with a plunger lift include: 

Revenue from increased production; 

Revenue from avoided emissions; 

Additional avoided costs—well treatment costs, 

reduced electricity costs, workover costs; and 

Salvage value. 

The most significant benefit of plunger lift installations is 

the resulting increase in gas production. During the 

decision process, the increase in production cannot be 

measured directly and must be estimated. The 

methodology for estimating this expected incremental 

production varies depending on the state of the well. The 

methodology for continuous or non-declining wells is 

relatively straightforward. In contrast, the methodology 

for estimating the incremental production for wells in 

decline is more complex. 

Estimating incremental gas production for nondeclining wells. The incremental gas production

from a plunger lift installation may be estimated by 

assuming that the average peak production rate

achieved after blowdown is near the potential peak

production rate for the well with fluid removed. A 

well log, like that illustrated in Exhibit 3, can be 

used to estimate the potential production increase. 

In this exhibit, the solid line shows well production 

rate gradually, then steeply declining as liquids 

accumulate in the tubing. Production is restored by 

venting the well to the atmosphere, but then declines 

again with reaccumulation of liquids. Note that the 

production rate scale, in thousands of cubic feet per

month, is a log scale. The dashed line shows the 

Exhibit 3: Incremental Production 

for Non-Declining Wells 

4 
 

 

 

 

 

Installing Plunger Lift Systems In Gas Wells 

(Cont’d) 

average peak production rate after liquids unloading.

This is assumed to be equal to the potential peak 

production rate that could be achieved with a 

plunger lift system, typically at least 80 percent of 

the peak production rate after blowdown. The 

shaded area between the potential production 

(dashed-line) and the actual well production (solidline) represents the estimate of incremental increase

in gas production that can be achieved with a 

plunger lift system. 

Estimating incremental production for 

declining wells or for situations in which the 

maximum production level after blowdown is 

not known. Wells that are in decline or operated 

without periodic blowdowns require more detailed

methods for estimating incremental production under

plunger lift systems. Plunger lift installations on

declining wells, for example, will require generating

an improved declining curve resulting from decreased 

pressure at perforations. Operators should seek the 

assistance of a reservoir engineer to aid in these

determinations (see Appendix). 

Once incremental production from a plunger lift 

installation is estimated, operators can calculate the 

value of incremental gas and estimate the economics 

of the plunger lift installation. Exhibit 4 presents an 

example of potential financial returns at different

levels of increase in gas production. It is important to

recognize that local costs and conditions may vary. 

Note also that the example in Exhibit 4 does not take 

Exhibit 4: Example of Estimated Financial 

Returns for Various Levels of Incremental 

Gas Production from a Plunger Installation 

Incremental Gas 

Production (Mcfd) 

Payout Time 

(months) 

Internal Rate of 

Return (%) 

3 14 71 

5 8 141 

10 4 309 

15 3 475 

20 2 640 

25 2 804 

30 2 969 

Assumptions: 

Value of gas = $7.00/Mcf. 

Plunger system cost of $7,772 including start-up cost. 

Lease operating expense of $790/year. 

Production decline of 6%/year. 

Source: Production Control Services, Inc. 

into account other financial benefits of a plunger lift

installation project, such as avoided emissions and 

decreased electricity and chemical treatment costs, 

which are described later in this Lessons Learned. 

Consideration of these additional benefits may

improve the already excellent financial returns of a 

plunger lift installation. 

Revenue from Avoided Emissions 

The amount of natural gas emissions reduced following

plunger lift installation will vary greatly from well to well,

based on the individual well and reservoir characteristics 

such as sales line pressure, well shut-in pressure, liquids 

accumulation rate, and well dimensions (depth, casing

diameter, tubing diameter). The most important variable,

however, is the normal operating practice of venting wells. 

Some operators put wells on automatic vent timers, while

others manually vent the wells with the operator standing 

by monitoring the vent, and still others open the well vent 

and leave, returning in hours or up to days, depending on

how long it typically takes the well to clear liquids. Thus, 

the economic benefits from avoided emissions will also 

vary considerably. Such wide variability means that some

projects will have much shorter payback periods than 

others. While most plunger lift installations will be 

justified by increased gas production rates alone, methane

emissions reductions can provide an additional revenue 

stream. 

Avoided emissions when replacing blowdowns.

In wells where plunger lift systems are installed,

emissions from blowing down the well can be 

reduced. Blowdown emissions vary widely in both 

their frequency and flow rates and are entirely well

and reservoir specific. Emissions attributable to 

blowdown activities have been reported from 1 Mcf 

per year to thousands of Mcf per year per well. 

Therefore, the savings attributable to avoided 

emissions will vary greatly based on the data for the

particular well being rehauled. 

Revenue from avoided emissions can be calculated by 

multiplying the market value of the gas by the 

volume of avoided emissions. If the emissions per 

well per blowdown have not been measured, they 

must be estimated. In the example below, the

amount of gas that is vented from a low pressure gas

well at each blowdown is estimated as 0.5625 times 

the sustained flow gas rate. This emission factor 

assumes that the integrated average flow over the 

blowdown period is 56.25 percent of full well flow. 

Using this assumption, Exhibit 5 demonstrates that 

5 
 

 

 

 

 

 

 

 

 

Installing Plunger Lift Systems In Gas Wells 

(Cont’d) 

for an unloaded well producing 100 Mcf per day, the 

gas vented to the atmosphere can be estimated at 2

Mcf per hour of blowdown. 

Exhibit 5: Example—Estimate Avoided 

Emissions from Blowdowns 

Avoided Emissions per Hour of 

Blowdowna 

= (0.56251 x Sustained Daily Flow 

Rate) / 24 hrs/day 

Avoided Emissionsb = (0.5625 x 100 Mcfd) / 24 

= 2 Mcf per hour of blowdown 

Annual Value of Avoided 

Emissionsc 

= 2 Mcf x 12 x $7.00/Mcf 

= $168 per year 

a Recommended methane emission factor reported in the joint GRI/EPA study, Methane Emissions From 

the Natural Gas Industry, Volume 7: Blow and Purge Activities (June 1995). The study estimated that at 

the beginning of a blowdown event, gas flow is restricted by fluids in the well to 25 percent of full flow. By 

the end of the blowdown event, gas flow is returned to 100 percent. The integrated average flow over the 

blowdown period is 56.25 percent of full well flow. 

b Assuming a sustained daily production rate of 100 Mcfd. 

c Assuming 1 blowdown per month lasting 1 hour. 

This method is simple to use, but anecdotal evidence 

suggests that it produces estimates of methane 

emissions avoided that are unrealistically low. For 

an alternate method for estimating avoided 

emissions from blowdowns, see the Appendix. 

Given the high degree of variability in emissions 

based on well and reservoir specific characteristics, 

measurement is the preferred method for 

determining avoided emissions. Field measurements 

can provide the data necessary to accurately

determine the savings attributable to avoided 

emissions. 

Avoided emissions when replacing beam lifts.

In cases where plunger lifts replace beam lifts rather 

than blowdowns, emissions will be avoided due to 

reduced workovers for mechanical repairs, to remove 

debris and cleanout perforations, to remove mineral 

scale and paraffin deposits from the sucker rods. The 

average emissions associated with workovers have

been reported as approximately 2 Mcf per workover; 

the frequency of workovers has been reported to 

range from 1 to 15 per year. Due to well-specific 

characteristics such as flow during workover, 

duration of workover, and frequency of workover, 

avoided emissions can vary greatly. 

Avoided Costs and Additional Benefits 

Avoided costs depend on the type of liquid removal systems 

currently in place, but can include avoided well treatment,

reduced electricity costs, and reduced workover costs. 

Avoided well treatment costs are applicable when plunger

lifts replace beam lifts or other remedial techniques such

as blowdown, swabbing, or soaping. Reduced electricity 

costs, reduced workovers, and recovered salvage value are 

only applicable if plunger lifts replace beam lifts. 

Avoided well treatment costs. Well treatment 

costs include chemical treatments, microbial 

cleanups, and removal of rods and scraping the 

borehole. Information from shallow 1,500-foot wells 

show well remediation costs including rod removal 

and tubing rehabilitation at more than $14,500 per

well. Chemical treatment costs (inhibitors, solvents, 

dispersants, hot fluids, crystal modifiers, and 

surfactants) are reported in the literature at a 

minimum of $13,200 per well per year. Microbial 

costs to reduce paraffin have been shown to be $6,600

per well per year (note that microbial treatments do

not address the fluids influx problem). Each of these 

treatment costs increases as the severity of the scale 

or paraffin increases, and as the depth of the well 

increases. 

Reduced electricity costs compared to beam 

lifts. Reduced electric operating costs further 

increase the economic return of plunger lifts. No 

electrical costs are associated with plunger lifts, 

because most controllers are solar-powered with 

battery backup. Exhibit 6 presents a range of 

avoided electricity costs reported by operators who

have installed plunger lifts. Assuming 365 days of 

operation, avoided electricity costs range from $1,000

to $7,300 per year. 

Reduced workover costs compared to beam 

lifts. Workover costs associated with beam lifts have 

been reported as $1,300 per day. While typical 

Exhibit 6: Electricity Costsa Avoided by Using a 

Plunger Lift in Place of a Beam Lift 

Motor Size (BHP) Operation Cost ($/day) 

10 

20 

30 

40 

50 

60 

3 

7 

10 

13 

17 

20 

a Electricity cost assumes 50 percent of full load, running 50 percent of the time, with cost of 7.5 cents/ 

kWh. 

6 
 

 

 

Installing Plunger Lift Systems In Gas Wells 

(Cont’d) 

workovers may take one day, wells more than 8,000 

feet deep will require more than one day of workover

time. Depending on the well, from 1 to 15 workovers 

can be required per year. These costs are avoided by 

using a plunger lift. 

Recovered salvage value when replacing a 

beam lift. If the plunger being installed is replacing 

a beam lift, extra income and a better economic 

return are realized from the salvage value of the old

production hardware. Exhibit 7 shows the salvage 

value that may be obtained by selling the surplus 

pumping units. In some cases, salvage sales alone 

may pay for the installation of plunger lifts. 

Exhibit 7: Salvage Valuea of Legacy 

Equipment When Converting from 

Beam Lift to Plunger Lift Operations 

Capital Savings from Salvaging Equipment 

Size of Pumping Unit (inch-lbs 

torque) Equipment Salvage Value ($) 

114,000 

160,000 

228,000 

320,000 

456,000 

640,000 

12,300 

16,800 

21,300 

27,200 

34,300 

41,500 

a Salvage costs include low estimate sale value of pumping unit, electric motor, and rod string. 

Step 4: Evaluate the plunger lift’s economics. 

A basic cash flow analysis can be used to compare the costs

and benefits of a plunger lift with other liquid removal 

options. Exhibit 8 shows a summary of the costs 

associated with each option. 

Economics of Replacing a Beam Lift with a 

Plunger Lift. In Exhibit 9 the data from Exhibit 8 

is used to model a hypothetical 100 Mcfd well and to 

evaluate the economics of plunger lift installation.

The increase in production is 20 Mcf per day, yielding

an annual increase in production of 7,300 Mcf. 

Assuming one workover per year prior to installation, 

the switch to a plunger lift also provides 2 Mcf of

avoided emissions per year. The project profits 

The average methane content of natural gas varies by natural gas 

industry sector. The Natural Gas STAR Program assumes the 

following methane content of natural gas when estimating 

methane savings for Partner Reported Opportunities. 

Production 79 % 

Processing 87 % 

Transmission and Distribution 94 % 

Methane Content of Natural Gas 

greatly from the salvage value of the surplus beam

lift equipment, yielding an immediate payback. Even 

if the salvage value is not recovered, the project may 

yield payback after only a few months depending on 

the well’s productivity. 

Economics of Avoiding Blowdown with a 

Plunger Lift. Exhibit 10 uses data from Exhibit 8 

to evaluate the economics of a hypothetical 100 Mcfd 

well at which a plunger lift is installed to replace

blowdown as the method for removing liquid from the 

well. Assuming the increased production is 20 Mcf

per day, the annual increase in production is 7,300

Mcf. In addition, there will be savings from avoided

emissions during blowdown. Assuming 12 one-hour

blowdowns per year, the avoided emissions are 24 

Mcf per year. 

Exhibit 8: Cost Comparison of 

Plunger Lift vs. Other Options 

Cost Category Plunger Lift Traditional 

Beam Lift 

Remedial 

Treatmenta 

Capital and 

Startup Costs 

Implementation 

Costs: 

Maintenanceb 

Well Treatmentc 

Electricald 

Salvage 

$1,943 -

$7,772 

$1,300/yr 

$0 

$0 

$0 

$25,907 -

$51,813 

$1,300 -

$19,500/yr 

$13,200+ 

$1,000 -

$7,300/yr 

($12,000 -

$41,500) 

$0 

$0 

$13,200+ 

$0 

$0 

a Includes soaping, swabbing, and blowing down. 

b For traditional beam lift, maintenance costs include workovers and assume 1 to 15 workovers per 

year at $1,300 per workover. 

c Costs may vary depending on the nature of the liquid. 

d Electricity costs for plunger lift: assume the lift is solar and well powered. 

7 
Installing Plunger Lift Systems In Gas Wells 

(Cont’d) 

Exhibit 9: Economic Analysis of Plunger Lift Replacing a Beam Lift 

Year 0 Year 1 Year 2 Year 3 Year 4 Year 5 

Value of Gas from Increased 

Production and Avoided 

Emissionsa 

$51,114 $51,114 $51,114 $51,114 $51,114 

Plunger Lift Equipment and 

Setup Cost ($7,772) 

Plunger Lift Maintenance ($1,300) ($1,300) ($1,300) ($1,300) ($1,300) 

Electric Cost per Year $0 $0 $0 $0 $0 $0 

Salvage Value Beam Lift 

Equipment $21,300 

Avoided Beam Lift 

Maintenance (1 workover/yr) $1,300 $1,300 $1,300 $1,300 $1,300 

Avoided Beam Lift Electricity 

Costs (10HP motor) $1,000 $1,000 $1,000 $1,000 $1,000 

Avoided Chemical Treatments $13,200 $13,200 $13,200 $13,200 $13,200 

Net Cash Inflow $13,528 $65,314 $65,314 $65,314 $65,314 $65,314 

NPV (Net Present Value) $261,119 b

 = 

Payback Period = Immediate 

a Gas valued at $7.00 per Mcf for 7,300 Mcf due to increased production and 2 Mcf from avoided emissions per event (based on 1 workover per year). b Net present value based on 10 percent discount rate over 5 years. 

Exhibit 10: Economic Analysis of Plunger Lift Replacing Blowdown 

Year 0 Year 1 Year 2 Year 3 Year 4 Year 5 

Value of Gas from Increased 

Production and Avoided 

Emissionsa 

Plunger Lift Equipment and 

Setup Cost 

Plunger Lift Maintenance 

Electric Cost per Year 

Avoided Chemical Treatments 

Net Cash Inflow 

$(7,772) 

$0 

($7,772) 

$51,268 

($1,300) 

$0 

$13,200 

$63,168 

$51,268 

($1,300) 

$0 

$13,200 

$63,168 

$51,268 

($1,300) 

$0 

$13,200 

$63,168 

$51,268 

($1,300) 

$0 

$13,200 

$63,168 

$51,268 

($1,300) 

$0 

$13,200 

$63,168 

Payback Period = 

NPV (Net Present Value)b

 = $231,684 

2 months 

a Gas valued at $7.00 per Mcf for 7,300 Mcf due to increased production and 24 Mcf from avoided emissions per event (based on 12 blowdowns per year and 2 Mcf per blowdown). b Net present value based on 10 percent discount rate over 5 years. 

8 
 

 

Installing Plunger Lift Systems In Gas Wells 

(Cont’d) 

When assessing options for installing plunger lift systems

on gas wells, natural gas price may influence the decision

making process. Exhibit 11 shows an economic analysis of

installing a plunger lift system rather than blowing down 

a well to the atmosphere to lift accumulated fluid at 

different natural gas prices. 

Exhibit 11: Gas Price Impact on 

Economic Analysis 

$3/Mcf $5/Mcf $7/Mcf $8/Mcf $10/ 

Mcf 

Value of 

Gas Saved $21,972 $36,620 $51,268 $58,592 $73,240 

Payback 

Period 

(months) 

3 2 2 2 2 

Internal 

Rate of 

Return 

(IRR) 

436% 624% 813% 907% 1095% 

Net 

Present 

Value 

(i=10%) 

$120,630 $176,157 $231,684 $259,448 $314,976 

Case Studies 

BP (formerly Amoco) Midland Farm Field 

Amoco Corporation, a Natural Gas STAR charter Partner 

(now merged with BP), documented its success in replacing

beam lift, rod pump well production equipment with

plunger lifts at its Midland Farm field. Prior to installing

plunger lift systems, Amoco used beam lift installations

with fiberglass rod strings. The lift equipment was 

primarily 640 inch-lb pumping units powered by 60 HP 

motors. Operations personnel noted that wells at the field 

were having problems with paraffin plating the well bore

and sucker rods, which blocked fluid flow and interfered 

with fiberglass sucker rod movement. Plunger lifts were

seen as a possible solution to inhibit the accumulation of 

paraffin downhole. 

Amoco began its plunger lift replacement program with a 

single-well pilot project. Based on the success of this 

initial effort, Amoco then expanded the replacement 

process to the entire field. As a result of the success in the 

Midland Farm field, Amoco installed 190 plunger lift units 

at its Denver City and Sundown, Texas locations, replacing 

other beam lift applications. 

Costs and Benefits 

Amoco estimated that plunger lift system installation costs

-including plunger equipment and tubing conversion costsaveraged $13,000 per well (initial pilot costs were higher 

than average during the learning phase, and the cost of 

tubing conversion is included). 

Amoco then calculated savings resulting from avoided 

costs in three areas—electricity, workover, and chemical 

treatment. Overall, Amoco estimated that the avoided 

costs of electricity, workover, and paraffin control averaged 

$24,000 per well per year. 

Electricity. Cost savings were estimated based on 50 

percent run times. Using the costs from Exhibit 6, the 

estimated electrical cost savings were estimated to be

$20 per day. 

Workover. On average, Amoco had one workover per

year per well to fix rod parts. With the old beam lift 

systems, the cost of this operation was $4,000, 

averaging about $11 per day. 

Chemical treatment. The biggest savings were 

realized from avoided chemical treatment. Amoco was 

able to save the approximately $13,000 per well per

year for paraffin control because the plunger operation

removed paraffin accumulation in the tubing. 

Increased Gas Production and Revenue 

For the initial plunger lift installation, Amoco realized an

increase in gas production of more than 400 Mcf per day.

Upon expansion of the plunger lift installation to the 

entire field, the company realized notable success in many

wells—although some showed little or no production

increase during the 30 day evaluation period. Total 

production increase (including both incremental 

production and non-emitted gas) across all wells where 

plunger lifts were installed was 1,348 Mcf per day. The 

average annual gas savings, which assumes a 6 percent 

production decline, was 11,274 Mcf per well or 

approximately $78,918 per well at 2006 prices. Exhibit 12 

and Exhibit 13 summarize the initial results and first year 

economics of Amoco’s Midland Farm plunger lift 

installation. In addition to the gas savings and cost

savings from the plunger lift installations, Amoco realized 

a one-time gain from the sale of surplus pumping units 

9 
 

Installing Plunger Lift Systems In Gas Wells 

(Cont’d) 

Exhibit 12: Change in Production Rates due to Plunger Lift Installation in Midland Farm Field, Texas 

a

Well # 

Production Before Plunger Lift Production 30 Days After Installation 

Gas (Mcfd) Oil (Bpd) Water (Bpd) Gas (Mcfd) Oil (Bpd) Water (Bpd) 

1 233 6 1 676 5 1 

2 280 15 1 345 15 1 

3 240 13 2 531 33 11 

4 180 12 2 180 16 3 

5 250 5 2 500 5 2 

6 95 8 2 75 12 0 

7 125 13 1 125 14 0 

8 55 6 1 55 13 2 

9 120 45 6 175 40 0 

10 160 16 3 334 17 3 

11 180 7 12 80 6 6 

12 215 15 4 388 21 2 

13 122 8 8 124 12 7 

14 88 5 10 23 9 1 

Avg. 167 12 4 258 16 3 

a All wells approximately 11,400 feet deep. 

Source: World Oil, November, 1995. 

Exhibit 13: BP Economics of Plunger Lifts Replacing Beam LIfts 

Average 

Annual Gas 

Savingsa 

(Mcf/year) 

Value of Gas 

Saved per 

Yearb 

Plunger Lift 

Installation 

Cost per Well 

Avoided Rod 

Workover 

Cost per Well 

per Year 

Avoided 

Chemical 

Treatment 

per Well per 

Year 

Avoided 

Electrical 

Costs per 

Well per Day 

Average 

Savings per 

Wellc 

Additional 

Salvage 

Value of 

Beam Lift 

per Well 

11,274 $78,918 $13,000 $4,000 $13,000 $20 $90,200 $41,500 

a

 Average initial gas production = 1,348 Mcfd. Assumes 6 percent annual production decline. b

 Gas valued at $7.00 per Mcf. 

c

 Value saved is averaged over 14 wells. 

10 
 

 

Installing Plunger Lift Systems In Gas Wells 

(Cont’d) 

and motors, resulting in additional revenue of $41,500 per 

installation. 

Analysis 

A summary of the costs and benefits associated with 

Amoco’s plunger lift installation program is provided below

in Exhibit 13. For the first year of operation, the company 

realized an average annual savings of approximately 

$90,200 per well at 2006 prices. In addition the company 

realized approximately $41,500 per well from salvage of 

the beam lift equipment at 2006 costs. 

ExxonMobil Big Piney Field 

At Big Piney Field in Wyoming, Natural Gas STAR charter

Partner Mobil Oil Corporation (now merged with Exxon)

has installed plunger lift systems at 19 wells. The first 

two plunger lifts were installed in 1995, and the remaining 

wells were equipped in 1997. As a result of these 

installations, Mobil reduced overall blowdown gas

emissions by 12,164 Mcf per year. In addition to the 

methane emission reduction, the plunger lift system

reduced the venting of ethane (6 percent by volume), C3

hydrocarbons + VOCs (5 percent), and inerts (2 percent). 

Exhibit 14 shows the emission reductions for each well 

after plunger lift installation. 

Installation Tips 

The following suggestions can help ensure trouble-free 

installation of a plunger lift system: 

Do not use a completion packer, because it limits 

the amount of gas production per plunger trip.

Without a completion packer, the entire annular void 

space is available to create a large compressed gas 

supply. The greater the volume of gas, the larger the 

volume of water that can be lifted. 

Check for tubing obstructions with a gauge ring 

before installation. Tubing obstructions hinder 

plunger movement and may require replacement of 

production tubing. 

Capture the plunger after the first trip.

Inspection of the plunger for the presence of any 

damage, sand, or scale will help prevent any

subsequent plunger lift operational difficulties, 

permitting immediate operational repair while the 

crew and installation equipment are mobilized. 

Lessons Learned 

Plunger lift systems offer several advantages over other

remedial treatments for removing reservoir fluids from 

wells: increased gas sales, increased well life, decreased

well maintenance, and decreased methane emissions. The 

following should be considered when installing a plunger 

lift system: 

Plunger lift installations can offer quick paybacks 

and high return on investments whether replacing a

beam lift or blowdowns. 

Plunger lift installations can greatly reduce the 

amount of remedial work needed throughout the 

Exhibit 14: Plunger Lift Program 

at Big Piney, Wyoming 

Well # 

Pre-Plunger 

Emission 

Volume 

(Mcf/yr/well) 

Post-Plunger 

Emission 

Volume 

(Mcf/yr/well) 

Annualized 

Reduction 

(Mcf/yr/well) 

1 1,456 0 1,456 

2 581 0 581 

3 1,959 318 1,641 

4 924 0 924 

5 105 24 81 

6 263 95 168 

7 713 80 633 

8 753 0 753 

9 333 0 333 

10 765 217 548 

11 1,442 129 1,313 

12 1,175 991 184 

13 694 215 479 

14 1,416 1,259 157 

15 1,132 708 424 

16 1,940 561 1,379 

17 731 461 270 

18 246 0 246 

19 594 0 594 

Totals 17,222 5,058 12,164 

11 
Installing Plunger Lift Systems In Gas Wells 

(Cont’d) 

lifetime of the well and the amount of methane 

vented to the atmosphere. 

An economic analysis of plunger lift installation

should include the incremental boost in productivity

as well as the associated extension in well life. 

Even when the well pressure declines below that 

necessary to lift the plunger and liquids against 

sales line back pressure, a plunger is more efficient 

in removing liquids with the well vented to the 

atmosphere than simply blowing the well without a 

plunger lift. 

Include methane emission reductions from installing 

plunger lift systems in annual reports submitted as 

part of the Natural Gas STAR Program. 

References 

Abercrombie, B. “Plunger Lift” in The Technology of Artificial Lift Methods, 

Vol. 2b, by K.E. Brown. PennWell Publishing Co., 1980 (pp. 483-

518). 

Beauregard, E., and P.L. Ferguson. Introduction to Plunger Lift: 

Applications, Advantages and Limitations. SPE Paper 21290 

presented at the Rocky Mountain Regional Meeting of the Society of 

Petroleum Engineers, Billings, MT, May 1982. 

Beeson, C.M., D.G. Knox, and J.H. Stoddard. Plunger Lift Correlation 

Equations and Nomographs. Paper 501-G presented at AIME 

Petroleum Branch Meeting, New Orleans, LA, October 1995. 

Bracy. C.L., and S.J. Morrow. An Economic Assessment of Artificial Lift in 

Low Pressure, Tight Gas Sands in Ochiltree County, Texas. SPE 

Paper 27932 presented at the SPE Mid-Continent Gas Symposium, 

Amarillo, TX, May 1994. 

Christian, J., Lea, J.F., and Bishop, B. Plunger Lift Comes of Age. World 

Oil, November 1995. 

EVI Weatherford, personal contact. 

Ferguson, Paul L., and Beauregard, E. Will Plunger Lift Work in My Well. 

Southwestern Petroleum Short Course, (pp. 301-310), 1988. 

Fishback II, J. William, Exxon-Mobil, personal contact. 

Foss, D.L., and R.B. Gaul. Plunger-Lift Performance Criteria with 

Operating Experience—Ventura Avenue Field. Drilling and 

Production Practice. American Petroleum Institute, 1965 (pp. 124-

140). 

Gregg, David, Multi Products Company, personal contact. 

GRI—EPA, Research and Development, Methane Emissions from the 

Natural Gas Industry, Volume 2: Technical Report. Prepared for the 

Energy Information Administration, GRI 94/0257.1, June 1996. 

GRI—EPA, Research and Development, Methane Emissions from the 

Natural Gas Industry, Volume 7: Blow and Purge Activities. Prepared 

for the Energy Information Administration, GRI 94/0257.24, June 

1996. 

Lea, J.F. Dynamic Analysis of Plunger Lift Operations. SPE Paper 10253 

presented at the 56th Annual Fall Technical Conference and 

Exhibition, San Antonio, TX, October 1981. 

McAllister, E.W. Pipe Line Rules of Thumb Handbook, Fourth Edition. Gulf 

Publishing Company, 1998 (pp. 282-284). 

O’Connell T., P. Sinner, and W.R. Guice. Flexible Plungers Resolve CT, 

Slim Hole Problems. American Oil and Gas Reporter, Vol. 40 No. 1 

(pp 82-85). 

Paugh, Len, Lomak Petroleum, personal contact. 

Phillips, Dan and Listik, Scott. How to Optimize Production from Plunger 

Lift Systems. World Oil, May 1998. 

Plunger Lift Systems, Inc., personal contact. 

Schneider, T., S., and Mackey, V. Plunger Lift Benefits Bottom Line for a 

Southeast New Mexico Operator. SPE Paper 59705 presented at the 

Permian Basin Oil land Gas Recovery Conference, Midland, TX , 

March 2000. 

Smith, Reid, BP, personal contact. 

Tingley, Kevin, U.S. EPA Natural Gas STAR Program, personal contact. 

Walls, Brad, Resource Production Company, personal contact. 

Well Master Corporation, personal contact. 

Wellco Service Corporation, personal contact. 

12 
 

Installing Plunger Lift Systems In Gas Wells 

(Cont’d) 

Appendix 

Estimating incremental production for declining wells. 

From Dake’s Fundamentals of Reservoir Engineering

(1982) we can use the following equation to calculate the 

increase in downhole flow for reduced pressure that may 

be seen when using a plunger lift. A semi-steady state 

inflow equation can be expressed as: 

m(pavg) - m(pwf) = [(1422 × Q × T)/(k × h)] × [ln(re/rw)­

3/4+S)] × (8.15) 

Where, 

m(pavg) = real gas pseudo pressure average 

m(pwf) = real gas pseudo pressure well flowing 

Q = gas production rate 

T = absolute temperature 

k = permeability 

h = formation height 

re = external boundary radius 

rw = wellbore radius 

S = mechanical skin factor 

After the reservoir parameters are gathered, this equation

can be solved for Q for the retarded flow with fluids in the 

hole (current conditions and current decline curve), and Q

for no fluids in the hole (plunger lift active and improved

decline curve). This is a guideline, and operators are 

reminded to use a reservoir engineer to aid in this 

determination. 

Alternate technique for calculating avoided emissions 

when replacing blowdowns. 

A conservative estimate of well venting volumes can be 

made using the following equation: 

Annual Vent Volume, Mscf/yr = (0.37×10-6) × (Casing 

Diameter)2 × Well Depth × Shut-in Pressure × Annual 

Vents 

Where casing diameter is in inches, well depth is in feet 

and shut-in pressure is in psig. Exhibit A1 shows an 

example calculation. 

Exhibit A1: Example—Estimate Avoided 

Emissions from Blowdowns 

Casing Diameter 8 inches 

Well Depth 10,000 feet 

Shut-in Pressure 214.7 psig 

Annual Vents 52 (weekly venting) 

Annual Vent Volume = (0.37 x 10-6) x 82

 x 10,000 x 214.7 x 52 = 2,644 

Mscf/yr 

This is the minimum volume of gas that would be vented

to atmospheric pressure from a well that has stopped 

flowing to the sales line because a head of liquid has

accumulated in the tubing equal to the pressure difference 

between the sales line pressure and well shut-in pressure. 

If the well shut-in pressure is more than 1.5 times the 

sales line pressure, as required for a plunger lift 

installation in Exhibit 2, then the volume of gas in the well

casing at shut-in pressure should be minimally sufficient 

to push the liquid in the tubing to the surface in slug-flow 

when back-pressure is reduced to zero psig. Partners can 

estimate the minimum time to vent the well by using this 

volume and the Weymouth gas-flow formula (worked out

for common pipe diameters, lengths and pressure drops in 

Tables 3, 4 and 5 in Pipeline Rules of Thumb Handbook, 

Fourth Edition, pages 283 and 284). If the Partner’s 

practice and experience is to vent the wells a longer time 

than calculated by these methods, the conservative Annual 

Vent Volume can be increased by a simple ratio of the 

actual vent times and the minimum vent time calculated 

using the Weymouth equation. 

13 
Installing Plunger Lift Systems In Gas Wells 

(Cont’d) 

United States 

Environmental Protection Agency 

Air and Radiation (6202J) 

1200 Pennsylvania Ave., NW 

Washington, DC 20460 

October 2006 

EPA provides the suggested methane emissions estimating methods contained in this document as a tool to develop basic methane emissions estimates only. As 

regulatory reporting demands a higher-level of accuracy, the methane emission estimating methods and terminology contained in this document may not conform to 

the Greenhouse Gas Reporting Rule, 40 CFR Part 98, Subpart W methods or those in other EPA regulations. 

14