vvEPA
United States
Environmental Protection
Agency
Air and Radiation
(6202J)
EPA430-B-01-004
July 2001
LESSONS LEARNED
FROM NATURAL GAS STAR PARTNERS
EPA POLLUTION PREVENTER
INSTALLING PLUNGER LIFT SYSTEMS IN GAS WELLS
Executive Summary
In mature gas wells, the accumulation of fluids in the wellbore can impede and, in some cases, halt pro-
duction. To keep gas flowing, accumulated fluids are commonly removed 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). As a result of these remedial operations, large volumes of
methane are emitted into the atmosphere.
Installing a plunger lift system is a cost-effective alternative for removing liquids, and has the additional
benefit of increasing production and significantly reducing methane emissions associated with blowdown
and other remedial operations. A plunger lift uses the well's remaining productive energy to lift the immo-
bile fluid column out of the well. By removing gas well liquids, the plunger lift system helps to maintain
production levels and eliminates the need for traditional remedial treatments.
Natural Gas STAR partners have reported 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 follow-
ing 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-spe-
cific and will vary considerably.
Volume of Gas From
Emissions Savings and
Avoided Emissions
(Mcf/year)
Install a plunger lift system 4,695 - 18,2502
Value of Saved
Gas'
$14,085-554,750
Average Cost
of Implementation
(S/well)
$5,000
Payback
: 6 months
1 Value of gas S3.00/Mct.
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 Cas STAR Program Best Management Practices (BMPs) and Partner Reported Opportunities (PROs). The
installation of plunger lift systems in gas wells often yields significant reductions in gas emissions and can extend well life.
-------
LESSONS LEARNED
FROM NATURAL GAS STAR PARTNERS
INSTALLING PLUNGER LIFT SYSTEMS IN GAS WELLS
Technology
Background
Liquid loading of the wellbore is often a serious problem in aging production wells.
Operators commonly use beam lifts or remedial techniques, such as venting or "blow-
ing 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 re-accumulate, resulting
in additional methane emissions.
Plunger lift systems are a
cost-effective alternative to
beam lifts and well blow-
downs and can significant-
ly reduce gas losses, elimi-
nate or reduce the fre-
quency of future well
treatments, and improve
well productivity. A plunger
lift system is -a form of
intermittent gas lift that
uses a swab or steel
plunger to lift fluids up the
well tubing to the surface.
The plunger serves as both
an interface between the
liquid and gas to minimize
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 nat-
ural buildup of pressure
during the shut-in of a well-
bore. The gas pressure is
used to force the plunger
and liquid load to the sur-
Exhibit 1: Plunger Lift Schematic
PLUNGERCATCHEH
ARRIVAL SHJSOR
BOTTOM HOLE BUNPER
' SPRING STANDNG VALVE
- SEATING NPFUITUBW3 STOP
~~~ GAS LIFT VALVE
Source: Production Control Services
Natural Gas STAR Lessons Learned 1
-------
face. A valve mechanism, controlled by a microprocessor, regulates gas input to the
casing and automates the process. In general, the operation of a typical plunger lift
involves the following steps:
1. The plunger begins near the bottom of the well on the bottom hole bumper spring.
2. Annulus gas pressure opens a downhole gas lift valve and creates the differential
pressure necessary to lift the plunger and liquid load to the surface.
3. Gas and produced liquids flow through the upper outlet in the plunger lift lubricator.
4. The gas lift valve closes downhole.
5. The plunger arrives in the lubricator and partially seals off the lower lubricator outlet.
6. Gas that has lifted the plunger is produced through the lower lubricator outlet.
7. As gas is produced, the lifting force on the plunger is released and the plunger drops
downhole to the bumper spring.
8. The cycle repeats.
~ ;~~~ The installation of a plunger lift system serves as a cost-effective alternative to beam
Economic and \\fa ancj we|| blowdowns that yields significant economic and environmental benefits.
Environmental The extent and nature of these benefits depends on the liquid removal system that
Benefits the Plun8er lift is replacing.
•& Lower capital cost versus installing beam lift equipment. The costs of
installing and maintaining a plunger lift are significantly less than the cost of beam
lift equipment. Costs do not increase with depth, provided production tubing is
part of the original well completion.
•& Lower well maintenance versus repetitive remedial treatments. Overall main-
tenance is reduced because repetitive remedial treatments such as swabbing or
well blowdowns become unnecessary with the continuous operation of the
plunger lift.
& Continuous production-improving gas rates and efficiency. Plunger lift sys-
tems can conserve the well's lifting energy and increase gas production. By
replacing well blowdowns, ongoing fluid removal permits the well to produce gas
continuously and avoid periods of halted gas production. In some cases, the
continuous removal of fluids yields higher daily gas production rates, often above
the previous decline curve.
•& Reduced paraffin and scale buildup. In .wells where paraffin or scale buildup is a
problem, the motion of the plunger may prevent paniculate buildup inside the tub-
ing. Thus, the need for chemical or swabbing treatments may be reduced or elimi-
nated. This is advantageous when the plunger lift is replacing a beam lift system as
well as well blowdowns.
•& Lower methane emissions. Eliminating repetitive remedial treatments and well
workovers also reduces methane emissions. Gas STAR partners have reported
annual gas savings averaging 600 thousand cubic feet (Mcf) per well by avoiding
blowdowns and an average of 30 Mcf per year by eliminating workovers.
2 Natural Gas STAR Lessons Learned
-------
Decision
Process
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 workover costs.
Moreover, wells that move water continuously out of the wellbore have the poten-
tial to produce more condensate and oil.
Operators should evaluate plunger lifts
as a replacement for well blowdowns
and beam lift equipment. The decision
to install a plunger lift system must be
made on a case-by-case basis. Well
operators can use the following deci-
sion process as a guide to evaluate the
applicability and cost-effectiveness of
plunger lift systems for gas production
wells.
Step 1: Determine the technical
feasibility of a plunger lift installa-
tion. Plunger lifts are applicable in wells
that have sufficient gas volume and gas
pressure to move liquids with some
assistance. Exhibit 2 lists four common
situations in which plunger lifts are
appropriate at a well. Vendors can sup-
ply written materials designed to help
well operators ascertain whether a par-
ticular well would benefit from the
installation of a plunger lift system.
Step 2: Determine the cost of
installing and operating a plunger
lift. Costs associated with plunger lifts
include capital and labor expenditures to
as ongoing costs to operate and maintain
Decision Process for Evaluating Installation
of Plunger Lift Systems:
1. Determine the technical feasibility of a
plunger lift installation.
2. Determine the cost of a plunger lift.
3. Estimate the savings achieved by plunger
lift installation.
4. Compare the overall costs and benefits
of plunger lifts vs. other techniques.
Exhibit 2: Common Plunger Lift Applications
Wells in which atmospheric blowdowns are
necessary to restore production.
Wells with a gas-to-liquid ratio of 400
scf/bbl per 1,000 feet of depth or greater.
Wells with shut-in wellhead pressure that is
1.5 times the sales line pressure.
Wells with scale or paraffin buildup.
purchase and install the equipment, as well
the system. These costs include:
Capital costs. A typical plunger lift system costs approximately $1,500 to $6,000.
In contrast, installation of surface pumping equipment, such as a beam lift, costs
between $20,000 and $40,000. Operators considering installing a plunger lift
should note that the system requires a continuous tubing string with a constant
internal diameter in good condition. The replacement of the tubing string, if
required, can considerably add to the cost of installation.
Operating costs. Plunger lift maintenance requires routine inspection of the lubri-
cator spring 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 com-
ponents are inspected annually.
Natural Gas STAR Lessons Learned 3
-------
Sfep 3: Estimate the savings achieved by plunger lift installation. The savings
associated with a plunger lift include:
•& Revenue from avoided emissions;
•& Revenue from increased production;
ft Avoided well treatment costs when plunger lifts replace beam lifts or other tech-
niques such as blowdown, swabbing, or soaping; and
•& Recovered salvage value, reduced electricity costs, and reduced workover costs
when replacing a beam lift.
Revenue from Increased Production
One of the most significant benefits of plunger lift installations is the resulting increase in
gas production. During the decision making 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 straight forward. In con-
trast, the methodology for estimating the incremental production for wells in decline or
wells where periodic blowdown data is not collected, is more complex.
•& Estimating incremental gas production for non-declining wells. For wells that
are not in decline (i.e., wells that maintain relatively constant flow rates when clear
of fluid accumulation), incremental gas production may be estimated by assuming
that the highest level of production achieved after blowdown is what the continu-
ous production rate would be if plunger lift systems were installed. Incremental pro-
duction is the difference between average current production and potential contin-
uous production, a calculation illustrated and described in Exhibit 3.
Exhibit 3: Estimating Incremental Production for Non-Declining Wells
1. Estimate the level of production under continuous production by taking the
maximum level of production achieved after each blowdown and multiplying by
the number of months in the period being examined.
2. Sum the actual production of all months in the period being examined.
3. Subtract the result of step 2 from the result of step 1.
Exhibit 4 depicts a theoretical production curve for a non-declining well, interrupted by
periods of fluid accumulation. These are times when gas would have been produced
using a plunger lift system. The exhibit shows the rapid resumption of production after
fluid accumulations have been cleared by blowdowns. The maximum production rate
after blowdown is assumed to be equal to the potential continuous production rate
using a plunger lift system. The white area below the potential continuous line is trie
incremental gas production resulting from using plunger lift systems.
4 Natural Gas STAR Lessons Learned
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Exhibit 4: Incremental Production for Non-Declining Wells
10.000
1.000
100
Jan-90 Ma/-90 May-90 Jul-90 Sep-90 Nov-90 Jan-91 Mar-91 May-91 Jul-91 Sep-91 Nov-91
-£ 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
decline curve resulting from decreased pressure at perforations. Operators should
use a reservoir engineer and appropriate resources such as Dake's Fundamentals
of Reservoir Engineering (1982) to aid in these determinations (see Appendix).
Once the volume of incremental production has been estimated, operators can convert
this volume into a dollar value or an associated return on investment. Exhibit 5 presents
the resulting financial returns at different increases in production levels. It is important to
Exhibit 5: Financial Returns at Varying Levels of Gas Sales Increases
Gas Sales Increase
(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 S3.00/Mcf Production decline of 6%/yr
Plunger system cost of $6,000 Discount rate of 15%
Lease operating expense of S600/mo
Source: Production Control Services, Inc.
Natural Gas STAR Lessons Learned 5
-------
recognize that local costs and conditions may vary. In addition, in some cases, it is possi-
ble that an increase in gas production may not be realized, or the well will continue to
decline. Engineers are advised to use this exhibit only as a guideline.
It should also be noted that an increase in gas production is often accompanied by an
increase in the production of other fluids-oil and water. An increase in oil production
can provide more revenue, but an increase in water production increases disposal
costs. Operators should consider these factors when evaluating plunger lift installations.
Revenue from Avoided Emissions
The amount of emissions reduced following plunger lift installation will vary greatly
from well to well based on the individual characteristics such as flow rate, frequency
of repairs, and duration of repair activities. Thus, the economic benefits from avoided
emissions will also vary considerably. Such wide variability means that some projects
will have much longer payback periods than others. Operators should carefully calcu-
late the estimated emissions reduction based on the characteristics of each well to
determine if installation of a plunger lift is cost-effective.
•& Avoided Emissions when Replacing Slowdowns. In wells where plunger lift sys-
tems are installed, emissions from blowing down the well can be reduced.
Slowdown 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 gas flow rate. This emission factor assumes that the inte-
grated average flow over the blowdown period is 56.25 percent of full well flow. Using
this assumption, 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 6: Estimating Avoided Emissions from Slowdowns
Avoided Emissions per Hour of Blowdown
Avoided Emissions2
Annual Value of Avoided Emissions'
= (0.56251 x Sustained Daily Flow Rate) + 24 hrs/day
= (0.5625 x 100Mcfd) + 24
- 2 Mcf per hour of blowdown
= 2 Mcf x 12x$3.00/Mcf
= $72 per year
' Recommended methane emission factor reported in the joint CRI/EPA study, Methane Emissions From the Natural
Gas Industry, Volume 7: Blow and Purge Activities (|une 1995). The study estimated that at the beginning of a blow-
down 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 TOO percent. The integrated average flow over the blowdown period is 56.25 percent of full
weBflow.
' Assuming a sustained daily production rate of 100 Mcfd
' Assuming 1 blowdown per month lasting 1 hour.
6 Natural Gas STAR Lessons Learned
-------
Given the high degree of variability in emissions based on well and reservoir specific
characteristics, measurement is the preferred method for determining avoided emis-
sions. 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. The average emissions associated with workovers have been
reported as approximately 2 Met per workover and the frequency of workovers
has been reported to range from 1 to 15 per year. Due to well-specific characteris-
tics such as flow during workover, duration of workover, and rrequency of
workovers 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 elec-
tricity 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 511,000 per well. Chemical treatment costs
(inhibitors, solvents, dispersants, hot fluids, crystal modifiers, and surfactants) are
reported in the literature at a minimum of S10,000 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 increase, 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. There are no electrical
costs with plunger lifts because most controllers are solar-powered with battery
backup. Exhibit 7 presents a range of avoided electricity costs reported by opera-
tors who have
installed plunger lifts.
Assuming 365 days
of operation, avoid-
ed electricity costs
range from $1,000
to $7,300 per year.
Exhibit 7: Electricity Costs' Avoided by Using a Plunger
Lift in Place of a Beam Lift
Motor Size (BHP)
10
20
30
40
50
60
Operation Cost i S<
day)
3
7
10
13
17
20
1 Electricity cost assumes 50 percent of full load, running 50 percent ot the time
with cost of 7.5 cents/kWh.
Natural Gas STAR Lessons Learned 7
-------
Reduced workover costs compared to beam lifts. Workover costs associated
with beam lifts have been reported as $1,000 per day. While typical workovers
may take one day, wells more than 8.000 feet deep will require more than one
day of workover time. Depending on the well, from 1 to 15 workovers can be
required per year. These costs are avoided by using a plunger lift.
Recovered salvage value when replacing a beam lift. If the plunger being
installed is replacing a beam lift, extra income and a better economic return are
realized from the salvage value of the old production hardware. Exhibit 8 shows
the salvage value that may be obtained by selling the surplus pumping units. In
some cases, salvage sales alone may pay for the installation of plunger lifts.
Exhibit 8: Salvage Value' of Legacy Equipment When
Converting From Beam Lift to Plunger Lift Operations
Capital Savings from Salvaging Equipment
Size of Pumping Unit
(inch-lbs torque)
114,000
160,000
228,000
320,000
456,000
640,000
Equipment Salvage Value ($)
9,500
13,000
16,500
2 1 ,000
26,500
32,000
' Salvage costs include low estimate sale value of pumping unit, electric motor, and
rod string.
Step 4: Compare the overall costs and benefits of plunger lifts versus other
techniques. A basic cash flow analysis can be used to compare the costs and bene-
fits of a plunger lift with other liquid removal options. Exhibit 9 shows a summary of
the costs associated with each option.
Exhibit 9: Cost Comparison of Plunger L
Cost Category
Capital Costs
Implementation Costs
Maintenance'
Well Treatment'
Electrical*
Salvage Value
of Old Equipment
Plunger Lift
$1,500-56,000
$1,000/yr
$0
$0
$0
ft vs. Other Options
Traditional
Beam Lift
$20,000 - $40,000
$1,000- 15,000/yr
$10,000*
$1,000-S7,300/yr
($9,000 - $32,000)
Remedial
Treatment1
SO
$0
$10,000+
$0
$0
' Includes soaping, swabbing, and blowing down.
1 For traditional beam lift maintenance costs include workovers and assume 1 to 1 5 workovers per year
at $1,000 per workover.
' Costs may vary depending on the nature of the liquid.
4 Electricity costs for plunger lift assume the lift is solar and well powered.
8 Natural Gas STAR Lessons Learned
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Economics of Replacing a Beam Lift with a Plunger Lift
In Exhibit 10, the data from Exhibit 9 is used to model a hypothetical 100 Mcfd well
and 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. If the salvage value is not
recovered, the project may yield payback after only a few months depending on the
well's productivity.
Exhibit 10: Economic Analysis of Plunger Lift Replacing a Beam Lift
Value of Gas From
Increased Production
and Avoided Emissions
(Mcf)'
Plunger Lift Installation
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
YearO
($5,000)
$0
516,500
$11,500
Year 1
$21,906
($1,000)
$0
$1,000
$1,000
$10,000
$32,906
Year 2
$21,906
($1,000)
$0
$1,000
$1,000
$10,000
$32,906
YearB
$21,906
($1,000)
$0
$1,000
$1,000
$10,000
$32,906
Year 4
$21,906
($1,000)
$0
$1,000
$1,000
$10,000
$32,906
YearS
$21,906
($1,000)
$0
$1,000
$1,000
$10,000
$32,906
NPV (Net Present Value)2 = $123,854
Payback Period1 = Immediate
1 Gas valued at $3.00 per Mcf for 7,300 Mcf due to increased production and 2 Mcf from avoided emissions per
event (based on " workover per year).
1 Net present value based on 10 percent discount rate over 5 years.
1 If the salvage value is not recovered, the payback period will vary from 1 to 6 months depending on weO productivity.
Economics of Avoiding Slowdown with a Plunger Lift
Exhibit 11 uses data from Exhibit 9 to evaluate the economics of a hypothetical 100
Mcfd well where 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.
Natural Gas STAR Lessons Learned 9
-------
Exhibit 11: Economic Analysis of Plunger Lift Replacing Slowdown
Value of Gas From and
Increased Production
Avoided Emissions
(Mcf)'
Plunger Lift Installation
Plunger Lift Maintenance.
Electric Cost per Year
Avoided Chemical Treatments
Net Cash Inflow
YearO
($5,000)
$0
($5,000)
Year 1
$21,972
($1,000)
$0
510,000
$30,972
Year 2
$21,972
($1,000)
$0
$10,000
$30,972
Year 3
$21,972
($1,000)
$0
$10,000
$30,972
Year 4
$21,972
($1,000)
$0
$10,000
$30,972
YearS
$21,972
(51,000)
$0
$10,000
$30,972
NPV (Net Present Value)2 = $102,189
Payback Period = <6 months
1 Gas valued at $3.00 per Mcf assuming 7,300 Mcf due to increased production and 24 Mcf in avoided emissions per
event (based on 1 2 bbwdowns per year).
• 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), doc-
umented 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 had
been using beam lift installations with downhole fiberglass rod strings. The lift equip-
ment was primarily 640 inch-lb pumping units powered by 60 HP motors. Operations
personnel noted that wells at the field were having problems such as paraffin coming
out of suspension and plating on 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. Later, as a result of the success in the Midland Farm field,
Amoco installed 190 plunger lift units in its Denver City, Texas and Sundown, Texas
locations replacing other beam lift applications.
Costs and Benefits
Amoco estimated that plunger lift system installation costs—including plunger equip-
ment and tubing conversion costs—averaged approximately $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.
10 Natural Gas STAR Lessons Learned
-------
ft Electricity. Cost savings were estimated based on 50 percent run times. Using the
costs from Exhibit 7, the estimated electrical cost savings per day were estimated at
$20.
ft Workover. On average, Amoco had one rod workover per year per well to fix rod
parts. With the old beam lift systems, the cost of this operation was $3,000, aver-
aging about $8 per day.
ft Chemical Treatment. The biggest savings were realized from avoided chemical
treatment. Amoco was able to save the approximately $10,000 per well per year
that had been necessary for paraffin control because the plunger operation pre-
vented accumulation in the wellbore.
Increased Gas Production and Revenue
At the initial well at which a plunger lift was installed, Amoco realized an increase in
gas production of over 400 Mcf per day. Upon expansion of the replacement process
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—with a value
of $4,044 per day, or $33,822 per year - assuming a 6% straight line decline in pro-
duction (see Exhibit 12 on next page).
In addition, Amoco gained additional revenue through the sale of surplus pumping
units and motors, resulting in additional income 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 13. Overall, the company realized an average
savings per well of approximately $44,700.
Exhibit 13: Amoco Economics of Plunger Lifts Replacing Beam Lifts
Gas
Volume
Saved
Per Day
(Mcf)
1,348
Value of
Gas Saved
Per Year1
$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
Salvage
Value of
Beam Lift
Per Well
$32,000
Average
Savings
Per Well2
$44,700
' Gas valued at $3.00 per Mcf.
2 Value saved is averaged over 14 wells.
Natural Gas STAR Lessons Learned 11
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Exhibit 12: Change in Production Rates due to Plunger Lift Installation in
Midland Farm Field, Texas
'Well*
1
2
3
4
5
6
7
8
9
10
11
12
13
14
Asg.
Production Before Plunger Lift
Gas
(Mcfd)
233
280
240
180
250
95
125
55
120
160
180
215
122
88
167
Oil
(8pd>
6
15
13
12
5
8
13
6
45
16
7
15
8
5
12
Water
(8pd)
1
1
2
2
2
2
1
1
6
3
12
4
8
10
4
Production 30 Days
After Installation
Gas
(Mcfd)
676
345
531
180
500
75
125
55
175
334
80
388
124"
23
258
Oil
CBpd)
5
15
33
16
5
12
14
13
40
17
6
21
12
9
16
Water
-------
Exhibit 14: Plunger Lift Program at Big Piney, Wyoming
Well*
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
Totals
Pre-PJunger
Emission Volume
(Mcf/yr/wefl)
1,458
581
1,959
924
105
263
713
753
333
765
1,442
1,175
694
1,416
1,132
1,940
731
246
594
17,224
Post-Plunger
Emission Volume
(Mcf/yr/weB)
0
0
318
0
24
95
80
0
0
217
129
991
215
1,259
708
561
461
0
0
5,058
Arnuaized Reduction
(Mcf/yr/weB)
1,458
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 pro-
duction per plunger trip. Without a completion packer, the plunger lift system is
free to use the entire annular void space to create a large gas cushion. A larger gas
cushion will allow more gas to be produced when the gas pressure pushes the
plunger to the surface.
ft Shut in the well the day before installation. This allows the casing pressure to
build up and may eliminate the need for swabbing to reduce the liquid weight on
the plunger.
•& Check for tubing obstructions with a gauge ring before installation. Tubing
obstructions hinder plunger movement and may require replacement of production
tubing.
•& Position the tubing as close to the perforations as possible. If the tubing is
placed above or below the perforations, the gas cushion must act against what
could be a significant hydrostatic pressure column. Proper tubing placement maxi-
mizes gas production.
Natural Gas STAR Lessons Learned 13
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Capture the plunger after the first trip. Inspection of the plunger for the pres-
ence of any damage, sand, or scale will deter any subsequent plunger lift opera-
tional difficulties, permitting immediate operational repair while the crew and instal-
lation equipment are mobilized.
Lessons
Learned
Plunger lift systems offer several advantages over other remedial treatments for remov-
ing 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 incremental
boost in productivity as well as the associated extension in well life.
Sources
Consulted
Carolyn Henderson - Natural Gas STAR Program
United States Environmental Protection Agency (6202J)
1200 Pennsylvania Ave., NW, Washington, DC 20460
Tel: (202) 564-2318, Fax: (202) 565-2254
Email: henderson.carolyn@epa.gov
Production Control Services, Inc
Tim O'Connell
Tel: (303) 575-0091
Multi Products Company
David Gregg
Tel: (330) 674-5981
Lomak Petroleum
Len Paugh
Tel: (724) 783-7144
Wellco Service Corporation
Tel: (405) 756-3156
Well Master Corporation
Tel: (800) 980-0254
Exxon-Mobil
J. William Fishback II
Tel: (405) 348-8683
Ferguson Beauregard
Stan Lusk
Tel: (903) 561-4851
Automation Associates
Jimmy Christian
Tel: (915) 697-0166
Plunger Lift Systems, Inc.
Tel: (800) 594-3887
EVI Weatherford
Tel: (713) 439-9400
14 Natural Gas STAR Lessons Learned
-------
P A M Abercrombie, B. "Plunger Lift" in The Technology of Artificial Lift Methods, Vol. 2b, by
tnd Notes K£ 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, CM., DC. 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.
Brady. C.L., and S.J. Morrow. "An Economic Assessment of Artificial Lift in Low
Pressure, Tight Gas Sands in Ochiltree County, TX." 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.
Dake, L.P. Fundamentals of Reservoir Engineering. Elsevier Science, 1982.
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).
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.
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).
Phillips, Dan and Listiak, Scott. "How to Optimize Production from Plunger Lift
Systems." World Oil, May 1998.
Ulanski, Wayne. Valve and Actuator Technology. McGraw-Hill, 1991.
Natural Gas STAR Lessons Learned 15
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Aooendix Fr°m Dake' Funclamentals of Reservoir Engineering (1982) we can use the following
PR aix 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(p^) - m(pj = [(1422 X Q X T ) / (k X h) ] X [ ln(re/rj - % + S)] X (8.15)
Where,
m(p^) = real gas pseudo pressure average
m(pvJ = real gas pseudo pressure well flowing
Q = gas production rate
T = absolute temperature
k = permeability
h = formation height
re = external boundary radius
rw = weflbore 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 determi-
nation.
16 Natural Gas STAR Lessons Learned
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SEPA
United States
Environmental Protection Agency
(6202J)
Washington, DC 20460
Official Business
Penalty for Private Use $300
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