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 $54,750. Benefits from both
increased gas production and emissions savings are well- and reservoir-specific and will vary considerably.
Action
Install a plunger
lift system
Potential Gas Savings from Incremental Gas
Production and Avoided Emissions (Mcf/year)
4,700 -18,2502 per well
Value of Gas
Saved ($)
$14,100-$54,750
Typical Setup and
Installation Costs
($/well)
$2,000-$8,000perwell
Typical
Payback
< 1 year
1 Value of gas $3.00/Mcf.
2 Based on results reported by Natural Gas STAR partners.
This is one of a series of Lessons Learned Summaries developed by EPA in cooperation with the natural gas industry on superior
applications of Natural Gas STAR Program Best Management Practices (BMPs) and Partner Reported Opportunities (PROs).
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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, how-
ever, 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 pres-
sure 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, con-
trolled 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 memory and program-
mable 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 locat-
ed at the base of the
well. As gas is pro-
duced to the sales
line, liquids accumu-
late in the well-bore,
creating a gradual
increase in back-
pressure that slows
gas production.
Exhibit 1: Plunger Lifts
Lubricator
Upper Outlet
Needle Valve
Plunger Catcher
Arrival Sensor
Master Valve
Solar Panel
Controller
Drip Pot
,..FLOW
Bottom Hole Bumper
Standing Valve
Seating Nipple/Tubing Stop
Gas Lift Valve
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2.
Economic and
Environmental
Benefits
3.
4.
5.
6.
To reverse the decline in gas production, the well is shut-in at the sur-
face 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.
As the plunger is lifted to the surface, gas and accumulated liquids
above the plunger flow through the upper and lower outlets.
The plunger arrives and is captured in the lubricator, situated across
the upper lubricator outlet.
The gas that has lifted the plunger flows through the lower outlet to
the sales line.
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 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.
The installation of a plunger lift system serves as a cost-effective alternative
to beam lifts and well blowdown and yields significant economic and envi-
ronmental 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 increas-
es efficiency. Plunger lift systems can conserve the well's lifting energy
and increase gas production. Regular fluid 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.
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Decision
Process
* 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 work overs 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 elimi-
nating 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.
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-by-case basis. Partners can use the following decision
process as a guide to evaluate the applicability and cost-effectiveness 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 expe-
rience 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 indi-
cators of plunger lift applicability.
Vendors often will supply written
materials designed to help opera-
tors 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, produc-
ing 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
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 lifts economics.
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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.
Exhibit 2: Common Requirements for Plunger Lift Applications
* 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.
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 installa-
tion costs approximately $1,500 to $6,000. In contrast, installation of sur-
face pumping equipment, such as a beam lift, costs between $20,000
and $40,000. 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 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 $500 to more than $2000.
Operators considering a plunger lift installation should note that the
system requires continuous tubing string with a constant internal diam-
eter 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 $500 to $1,000 per
year. Other system components are inspected annually.
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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.
Revenue from Increased Production
The most significant benefit of plunger lift installations is the resulting
increase in gas production. During the decision process, the increase in pro-
duction cannot be measured directly and must be estimated. The methodol-
ogy 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 non-declining wells. The
incremental gas production from a plunger lift installation may be esti-
mated 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.
Exhibit 3: Incremental Production for Non-Declining Wells
100,000
10,000
Mcf/Month
100
Production Control Services
Spiro Formation Well 9N-27E
— Well Production — Pot
-\ without Plunger Lift — Producl
h
X1
— 1 v\lk — H —
\ UN
\
ii i \ i
ential
ion wi
r\ '
r\
Continuous
th Plunger Lifts —
-i-vA4-A
|-|T-\7
j| U
u
II 1
1990 .. 1991 1992 1993 1994 1995 1996
TIME
Potential Incremental
Well Slowdowns pmduction wjth p|unger L|ft
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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 reaccu-
mulation of liquids. Note that the production rate scale, in thousands of
cubic feet per month, is a log scale. The dashed line shows the 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 blow-
down. The shaded area between the potential production (dashed-line) and
the actual well production (solid-line) 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 situa-
tions in which the maximum production level after blowdown is not
known. Wells that are in decline or operated without periodic blow-
downs require more detailed methods for estimating incremental pro-
duction 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 determina-
tions (see Appendix).
Once incremental production from a plunger lift installation is estimated,
operators can calculate the value of incremental gas and estimate the eco-
nomics 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 into account other financial ben-
efits 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.
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Exhibit 4: Example of Estimated Financial Returns for Various Levels
of Incremental Gas Production from a Plunger Installation
Incremental Gas
Production (Mcfd)
3
5
10
15
20
25
30
Payout Time
(Months)
28
16
8
5
4
3
3
Internal Rate of
Return (%)
38
69
144
219
294
369
444
Return on
Investment (%)
350
580
1,150
1,730
2,310
2,880
3,460
Assumptions:
Value of gas $3.00/Mcf.
Plunger system cost of $6,000 including start-up cost.
Lease operating expense of $600/month.
Production decline of 6%/year.
Discount rate of 15%.
Source: Production Control Services, Inc.
Revenue from Avoided Emissions
The amount of natural gas emissions reduced following plunger lift installa-
tion will vary greatly from well to well, based on the individual well and reser-
voir 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 installa-
tions will be justified by increased gas production rates alone, methane gas
emissions reductions can provide an additional reserve 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 frequen-
cy 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 attrib-
utable to avoided emissions will vary greatly based on the data for the
particular well being rehauled.
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Revenue from avoided emissions can be calculated by multiplying the mar-
ket 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 assump-
tion, Exhibit 6 demonstrates that 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 Slowdowns
Avoided Emissions per Hour of Blowdown = (0.56251 x Sustained Daily Flow Rate)
+ 24 hrs/day
Avoided Emissions2 = (0.5625 x 100 Mcfd) ^ 24
= 2 Mcf per hour of blowdown
Annual Value of Avoided Emissions3 = 2 Mcf x 12 x $3.00/Mcf
= $72 per year
1 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 blow-
down period is 56.25 percent of full well flow.
2 Assuming a sustained daily production rate of 100 Mcfd.
3 Assuming 1 blowdown per month lasting 1 hour.
This method is simple to use, but anecdotal evidence suggests that it pro-
duces 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 determin-
ing 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 blow downs, 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
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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 remedia-
tion costs including rod removal and tubing rehabilitation at more than
$11,000 per well. Chemical treatment costs (inhibitors, solvents, disper-
sants, hot fluids, crystal modifiers, and surfactants) are reported in the lit-
erature at a minimum of $10,000 per well per year. Microbial costs to
reduce paraffin have been shown to be $5,000 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 con-
trollers 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 electrici-
ty costs range from $1,000 to $7,300 per year.
Exhibit 6: Electricity Costs
Motor Size (BHP)
10
20
30
40
50
60
Avoided by Using a Plunger Lift in
of a Beam Lift
Operation Cost ($/day)
3
7
10
13
17
20
1 Electricity cost assumes 50 percent of full load, running 50 percent of the time
cost of 7.5 cents/kWh.
Place
, with
10
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Reduced workover costs compared to beam lifts. Workover costs
associated with beam lifts have been reported as $1,000 per day. While
typical workovers may take one day, wells more than 8,000 feet deep
will require more than one day of workover time. Depending on the well,
from 1 to 15 workovers can be required per year. These costs are avoid-
ed by using a plunger lift.
Recovered salvage value when replacing a beam lift. If the plunger
being installed is replacing a beam lift, extra income and a better eco-
nomic return are realized from the salvage value of the old production
hardware. Exhibit 7 shows the salvage value that may be obtained by
selling the surplus pumping units. In some cases, salvage sales alone
may pay for the installation of plunger lifts.
Exhibit
7: Salvage Value1 of Legacy Equipment When Converting
Beam Lift to Plunger Lift Operations
from
Capital Savings from Salvaging Equipment
1 Salvage
string.
Size of Pumping Unit
(inch-lbs torque)
114,000
160,000
228,000
320,000
456,000
640,000
costs include low estimate
Equipment Salvage Value
($)
9,500
13,000
16,500
21,000
26,500
32,000
sale value of pumping unit, electric motor, and rod
11
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Step 4: Evaluate the plunger lifts 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.
Exhibit 8: Cost Comparison of Plunger Lift vs. Other Options
Cost Category Plunger Lift Traditional Beam Lift Remedial
Treatment1
Capital and Startup Costs $1,500-$6,000
Implementation Costs:
Maintenance2 $1,000/yr
Well Treatment3 $0
Electrical4 $0
Salvage $0
$20,000 - $40,000
$1,000-$15,000/yr
$10,000+
$1,000-$7,300/yr
($9,000-$32,000)
$10,000+
1 Includes soaping, swabbing, and blowing down.
2 For traditional beam lift maintenance costs include workovers and assume 1 to 15
workovers per year at $1,000 per workover.
3 Costs may vary depending on the nature of the liquid.
4 Electricity costs for plunger lift assume the lift is solar and well powered.
12
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* 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 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.
Exhibit 9: Economic Analysis of Plunger Lift Replacing a Beam Lift
Value of Gas from
Increased Production
and Avoided Emissions1
Plunger Lift Equipment
and Setup Cost
Plunger Lift Maintenance
Electric Cost per Year
Salvage Value Beam
Lift Equipment
Avoided Beam Lift
Maintenance
(1 workover/yr)
Avoided Beam Lift
Electricity Costs
(10HP motor)
Avoided Chemical
Treatments
Net Cash Inflow
1 Gas valued at $3.00 per
from avoided emissions
2 Net present value basec
YearO Yearl Year 2 Year 3 Year 4
$21,906 $21,906 $21,906 $21,906
($6,000)
($1,000) ($1,000) ($1,000) ($1,000)
$0 $0 $0 $0 $0
$16,500
$1,000 $1,000 $1,000 $1,000
$1,000 $1,000 $1,000 $1,000
$10,000 $10,000 $10,000 $10,000
$10,500 $32,906 $32,906 $32,906 $32,906
NPV (Net Present Value)2
Payback Period =
Mcf for 7,300 Mcf due to increased production and
per event (based on 1 workover per year).
on 10 percent discount rate over 5 years.
Years
$21,906
($1,000)
$0
$1,000
$1,000
$10,000
$32,906
= $122,945
Immediate
2 Mcf
13
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* Economics of Avoiding Slowdown 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 pro-
duction 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 10: Economic Analysis of Plunger Lift Replacing Blowdown
YearO Year) Year 2 Year 3 Year 4 Year 5
Value of Gas from
Increased Production
and Avoided Emissions1
Plunger Lift Equipment
and Setup Cost
Plunger Lift Maintenance
Electric Cost per Year
Avoided Chemical
Treatments
Net Cash Inflow
$21,972 $21,972 $21,972 $21,972 $21,972
($6,000)
($1,000) ($1,000) ($1,000) ($1,000) ($1,000)
$0 $0 $0 $0 $0 $0
$10,000 $10,000 $10,000 $10,000 $10,000
($6,000) $30,972 $30,972 $30,972 $30,972 $30,972
NPV (Net Present Value)2 = $101 ,280
Payback Period = < 6 months
1 Gas valued at $3.00 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).
2 Net present value based on 10 percent discount rate over 5 years.
Case Studies
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 produc-
tion 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.
14
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Costs and Benefits
Amoco estimated that plunger lift system installation costs-including plunger
equipment and tubing conversion costs-averaged $10,000 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
$20,000 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 sav-
ings 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 $3,000, averaging about $8 per day.
* Chemical treatment. The biggest savings were realized from avoided
chemical treatment. Amoco was able to save the approximately $10,000
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 pro-
duction 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 $33,822 per well. Exhibit 11 and Exhibit 12 summarize the ini-
tial 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 and motors, resulting in additional revenue of $32,000 per
installation.
Analysis
A summary of the costs and benefits associated with Amoco's plunger lift
installation program is provided below in Exhibit 12. For the first year of
operation, the company realized an average annual savings of approximately
$44,700 per well. In addition the company realized approximately $32,000
per well from salvage of the beam lift equipment.
15
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Exhibit 11: Change in Production Rates due
Installation in Midland Farm Field,
'Well #
Production Before
Plunger Lift
Gas Oil
(Mcfd) (Bpd)
1
2
3
4
5
6
7
8
9
10
11
12
13
14
Avg.
233
280
240
180
250
95
125
55
120
160
180
215
122
88
167
6
15
13
12
5
8
13
6
45
16
7
15
8
5
12
1 All wells approximately 1 1 ,400 feet
Source: World Oil, November, 1995
Water
(Bpd)
1
1
2
2
2
2
1
1
6
3
12
4
8
10
4
deep.
to Plunger Lift
Texas
Production 30 Days
After Installation
Gas
(Mcfd)
676
345
531
180
500
75
125
55
175
334
80
388
124
23
258
Oil
(Bpd)
5
15
33
16
5
12
14
13
40
17
6
21
12
9
16
Water
(Bpd)
1
1
11
3
2
0
0
2
0
3
6
2
7
1
3
Exhibit 12: Amoco Economics of Plunger Lifts Replacing Beam Lifts
Average
Annual
Gas
Savings1
(Mcf/
Year)
11,274
Value of
Gas
Saved
per
Year2
$33,822
Plunger
Lift
Installation
Cost
per Well
$10,000
Avoided
Rod
Workover
Cost
per Well
per Year
$3,000
Avoided
Chemical
Treatment
per Well
per Year
$10,000
Avoided
Electrical
Costs
per Well
per Day
$20
Average
Savings
per
Well3
$44,700
Additional
Salvage
Value of
Beam Lift
per Well
$32,000
1 Average initial gas production = 1,348 Mcfd. Assumes 6 percent annual production
decline.
2 Gas valued at $3.00 per Mcf.
3 Value saved is averaged over 14 wells.
Mobil 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
16
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reduced overall blowdown gas emissions by 12,166 Mcf per year. In addi-
tion to the methane emission reduction, the plunger lift system reduced the
venting of ethane (6 percent by volume), C3 hydrocarbons + VOCs (5 per-
cent), and inerts (2 percent). Exhibit 13 shows the emission reductions for
each well after plunger lift installation.
Well*
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
Totals
Exhibit 13: Plunger
Pre-Plunger Emission
Volume (Mcf/yr/well)
1,456
581
1,959
924
105
263
713
453
333
765
1,442
1,175
694
1,416
1,132
1,940
731
246
594
17,224
Lift Program at Big Piney,
Wyoming
Post-Plunger Emission Annualized Reduction
Volume (Mcf/yr/well) (Mcf/yr/well)
0
0
318
0
24
95
80
0
0
217
129
991
215
1,259
708
561
461
0
0
5,058
1,456
581
1,641
924
81
168
633
753
333
548
1,313
184
479
157
424
1,379
270
246
594
12,166
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.
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Lessons
Learned
* Check for tubing obstructions with a gauge ring before installation.
Tubing obstructions hinder plunger movement and may require replace-
ment 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 subse-
quent plunger lift operational difficulties, permitting immediate operational
repair while the crew and installation equipment are mobilized.
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 lifetime of the well and the amount of methane
vented to the atmosphere.
* An economic analysis of plunger lift installation should include the incre-
mental 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.
18
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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 PL. 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 pre-
sented at the SPE Mid-Continent Gas Symposium, Amarillo, IX, 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 pre-
sented 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
19
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Sysfems. World Oil, May 1998.
Plunger Lift Systems, Inc., personal contact.
Schneider, T., S., and Mackey, V. Plunger Lift Benefits Bottom Line fora
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.
20
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Estimating incremental production for declining wells.
Appendix
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)-ni(pj=[(1422 x Q x T)/(k x h)] x [ln(re/rw)^3/4+S)] x (8.15)
Where,
m(pavg) = real gas pseudo pressure average
m(Pwf) = real 9as 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.
21
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Alternate technique for calculating avoided emissions when replacing
blowdowns.
A conservative estimate of well venting volumes can be made using the fol-
lowing equation:
Annual Vent Volume, Mscf/yr = (0.37x106) x (Casing Diameter)2 x
Well Depth x Shut-in Pressure x 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 = (0.37x106) 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.
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United States
Environmental Protectic
Air and Radiation (620-
1200 Pennsylvania Avu
Washington, DC 2046C
EPA430-B-03-OOE
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