Lessons Learned
from Natural Gas STAR Partners

NaturalGas^S
O	EPA POLLUTION PREVENTER '
*
3"
3D
o
\ c
*1 PRO^
Options for Removing Accumulated Fluid and
Improving Flow in Gas Wells

Executive Summary
When first completed, many natural gas wells have
sufficient reservoir pressure to flow formation fluids
(water and liquid hydrocarbon) to the surface along with
the produced gas. As gas production continues, the
reservoir pressure declines, and as pressure declines, the
velocity of the fluid in the well tubing decreases.
Eventually, the gas velocity up the production tubing is no
longer sufficient to lift liquid droplets to the surface.
Liquids accumulate in the tubing, creating additional
pressure drop, slowing gas velocity, and raising pressure
in the reservoir surrounding the well perforations and
inside the casing. As the bottom well pressure approaches
reservoir shut-in pressure, gas flow stops and all liquids
accumulate at the bottom of the tubing. A common
approach to temporarily restore flow is to vent the well to
the atmosphere (well "blow down"), which produces
substantial methane emissions. The U.S. Inventory of
Greenhouse Gas Emissions and Sinks 1990—2008
estimates 9.6 billion cubic feet (Bel) of annual methane
emissions from venting of low pressure gas wells.
At different stages in the life of a gas well, various
alternatives to repeated well venting can be deployed to
move accumulated liquids to the surface. These options
include:
~	Foaming agents or surfactants
~	Velocity tubing
~	Plunger lift, operated manually or with 'smart' well
automation
~	Downhole pumps, which include reciprocating (beam)
pumps and rotating (progressive cavity) pumps.
Natural Gas STAR Partners report significant methane
emission reductions and economic benefits from
implementing one or more lift options to remove
accumulated liquids in gas wells. Not only are vented
methane emissions reduced or eliminated, but these lift
techniques can provide the additional benefit of increased
gas production.
Economic and Environmental Benefits
Method for
Reducing
Natural Gas
Losses
Volume of Natural
Gas Savings and
Incremental
Production1
(Mcf/well/year)
Value of Natural Gas Savings
and Additional Production
(Mcf/well/year)
$3 per Mcf $5 per Mcf $7 per Mcf
Implementation
Cost1
(2010 $/Well)
Project Payback (years)
$3 per Mcf $5 per Mcf $7 per Mcf
Use Foaming
Agents
500 - 9,360
$1,500 -
$28,080
$2,500 -
$46,800
$3,500 -
$65,520
$500 - $9,880
0 to 7
0 to 4
0 to 3
Install Velocity
Tubing
9,285 - 27,610
$27,855 -
$82,830
$46,425 -
$138,050
$64,995 -
$193,270
$7,000 - $64,000
0 to 3
0 to 2
0 to 1
"Smart" Well
Automated
Controls for
Plunger Lift2
800 - 1,4632
$2,400 -
$4,389
$4,000 -
$7,315
$5,600 -
$10,241
$5,700 - $18,000
1 to 8
1 to 5
1 to 4
Install Rod
Pumps and
Pumping
Units2
973 - 2,0402
$2,919 -
$6,120
$4,865 -
$10,200
$6,811 -
$14,280
$41,000 - $62,000
6 to 22
4 to 13
3 to 10
1 Based on results reported by Natural Gas STAR Partners
2Does not include incremental gas production. Includes only potential gas savings from avoided well venting.
1

-------
Options for Removing Accumulated Fluid and Improving Flow in Gas Wells
(Cont'd)
By avoiding or reducing well blow downs, Partners report
annual methane emissions savings that range from 500
thousand cubic feet (Mel) per well to more than 27,000
Mcf/well. The benefit of increased gas production will vary
considerably among individual wells and reservoirs, but
can be substantial. For example, Partners report that
increased gas production following plunger lift installation
yielded as much as 18,250 Mcf per well.
Technology Background
Most gas wells will have liquid loading occur at some point
during the productive life of the well. When this occurs, a
common course of action to improve gas flow includes:
*	Shutting-in the well to allow bottom hole pressure to
increase,
*	Swabbing the well to remove accumulated fluids,
*	Venting the well to the atmosphere (well blowdown),
*	Installing an artificial lift system.
'No-Emissions' Solutions for
Liquid Loading in Gas Wells:
~	Foaming Agents/ Surfactants
-	Low cost/ low volume lift method
-	Applied early in production decline, when the bottom
hole pressure still generates sufficient velocity to lift
liquid droplets
*	Velocity Tubing
-	Low maintenance, effective for low volumes lifted
-	Somewhat expensive to acquire and install
-	Often deployed in combination with foaming agents
~	Plunger Lift
-	Long lasting
-	Less expense to install and operate than a pumping
unit
-	Often, plunger lift cannot produce a well to its economic
limit (abandonment).
-	Challenging to operate effectively; requires more time
and expertise to manage.
*	Rod Pumping Units
-	Can be deployed in applications to remove greater liq-
uid volumes than plunger lift.
Swabbing and "blowing down" a well to temporarily
restore production can vent significant methane emissions,
from 80 to 1600 Mcf/year per well. The process must be
repeated as fluids reaccumulate, resulting in additional
methane emissions. Operators may wait until well
blowdown becomes increasingly ineffective before
implementing some type of artificial lift. At this point, the
cumulative methane emissions from a well could be
substantial.
Natural Gas STAR Partners have found that applying
artificial lift options early in the life of a well offers
significant emissions savings and economic benefits. Each
method for lifting liquid in a well has advantages and
disadvantages for prolonging the economic life of a well.
Total gas savings and methane emission reductions that
result from reducing or eliminating well venting will vary
for each well depending on flow line operating pressure,
reservoir pressure, liquid volume, specific gravity and the
number of blowdowns eliminated.
Fluid Removal Options for Gas Wells
Foaming Agents
The use of foam produced by surfactants can be effective
for gas wells that accumulate liquid at low rates (Exhibit
1). Foam reduces the density and surface tension of the
fluid column, which reduces the critical gas velocity needed
to lift fluids to surface and aids liquid removal from the
well. Compared to other artificial lift methods, foaming
agents are one of the least costly applications for unloading
gas wells. Foaming agents work best if the fluid in the
well is at least 50 percent water. Surfactants are not
Exhibit 1: Liquid Foaming Agent
Source: S. Bumgardner, Advanced Resources International, inc.
2

-------
Options for Removing Accumulated Fluid and Improving Flow in Gas Wells
(Cont'd)
effective for natural gas liquids or liquid hydrocarbons.
Surfactants are delivered to the well as soap sticks or as a
liquid injected directly into the casing-tubing annulus or
down a capillary tubing string. For shallow wells, the
surfactant delivery can be as simple as the operator
periodically pouring surfactant down the annulus of the
well through an open valve. For deep wells, a surfactant
injection system requires the installation of surface
equipment, as well as regular monitoring. The surface
equipment includes a surfactant or 'soap' reservoir, an
injection pump, a motor valve with a timer (depending on
the installation design), and a power source for the pump
(Exhibit 2). No equipment is required in the well,
although foaming agents and velocity tubing may be more
effective when used in combination.
Source: S. Bumgardner, Advanced Resources International, inc.
Electric pumps can be powered by AC power where
available or by solar power to charge batteries. Other
pump choices include mechanical pumps that are actuated
by the movement of another piece of equipment or
pneumatic pumps actuated by gas pressure. Different
pump types have different advantages with respect to
reliability, precision, remote operation, simplicity,
maintenance frequency, efficiency, and equipment
compatibility.
Velocity Tubing
The velocity at which gas flows through pipe determines
the capacity to lift liquids. When the gas flow velocity in a
well is not sufficient to move reservoir fluids, the liquids
will build up in the well tubing and eventually block gas
flow from the reservoir. One option to overcome liquid
loading is to install smaller diameter production tubing or
'velocity tubing'. The cross-sectional area of the conduit
through which gas is produced determines the velocity of
flow and can be critical for controlling liquid loading. A
velocity string reduces the cross-sectional area of flow and
increases the flow velocity, achieving liquid removal while
limiting blowdowns to the atmosphere.
Exhibit 3 shows that the conduit for gas flow up a wellbore
can be either production tubing, the casing-tubing annulus
or simultaneous flow through both the tubing and the
annulus. In any case, a 2004 study estimated that gas
velocity must be at least 5 to 10 ft/sec (300 to 600 ft/min) to
effectively remove hydrocarbon liquids from a well, and at
least 10 to 20 ft/ sec (600 to 1200 ft/min) to move produced
water. As a rule of thumb, gas flow velocity of 1,000 feet
per minute is needed to remove liquid. These figures
assume used pipe in good condition with low relative
roughness of the pipe wall.
Exhibit 3: Velocity Tubing
Entrained Liquids
Production Tubing
Production Packer
Coiled Tubing
Velocity String
Perforations
Wellbore Liquids
Float Shoe
Source: S. Bumgardner, Advanced Resources International, inc.
Exhibit 2: Soap Stick Launcher with
Automatic Controller
Launch Button
Supply Gas
Regulator
Access-—
Supply Gauge
Drip Pot-
Junction Box
Vent Valve'
Pressure
Transducer
Bypass,
Equalizer
Actuated
Valve
Valve
'Controller
Gas Flow
3

-------
Options for Removing Accumulated Fluid and Improving Flow in Gas Wells
(Cont'd)
The installation of a velocity string is relatively simple and
requires calculation of the proper tubing diameter to
achieve the required velocity at the inlet and outlet
pressures of the tubing. Velocity tubing to facilitate liquid
removal can be successfully deployed in low volume gas
wells upon initial completion or near the end of their
productive lives. Candidate wells include marginal gas
wells producing less than 60 Mfcd. Installation of velocity
tubing requires a well workover rig to remove the existing
production tubing and place the smaller diameter tubing
string in the well.
Coiled tubing may also be used, allowing for easier
installation and the application of a greater range of
tubing diameters as small as 0.25 inches. Coiled tubing
can be applied in wells with lower velocity gas production
due to better relative roughness characteristics of the
tubing and the absence of pipe joint connections. Studies
indicate that seamed coiled tubing provides better lift
characteristics due to the elimination of turbulence in the
flow stream because the seam acts as a "straightening
vane".
Plunger Lift with Smart' Well Automation
Plunger lifts are commonly used to lift fluids from gas
wells. 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 a column of fluid
above the plunger up the well tubing to the surface.
Exhibit 4 shows a conventional plunger lift installation on
a gas well.
The operation of a plunger lift system relies on pressure
buildup in a gas well during the time that the well is shut-
in (not producing). The well shut-in pressure must
significantly exceed the sales line pressure in order to lift
the plunger and load of accumulated fluid to the surface
against the sales line backpressure. A companion Lessons
Learned paper, Installing Plunger Lift Systems in Gas
Wells, discusses the installation, gas savings and
economics of plunger lift systems. The focus of the present
Lessons Learned paper are the incremental gas savings
obtained from installing 'smart' automation systems to
better manage the operation of plunger lift installations on
a field-wide or basin-wide scale.
Most plunger systems operate on a fixed time cycle or on a
preset differential pressure. Regardless of activation
system (manual, fixed time cycle, or preset pressure
differential), a valve mechanism and controller at the
surface cause gas volume and pressure to build up in the
wellbore initiating the plunger release cycle. At this point,
the surface valve closes and the plunger drops to the
bottom of the well. Once adequate pressure is reached, the
surface valve opens and the plunger rises to the surface
with the liquid load. Insufficient reservoir energy, or too
much fluid buildup can overload a plunger lift. When that
occurs, venting the well to the atmosphere (well blow down)
instantaneously reduces the backpressure on the plunger
and usually allows the plunger to return to the surface.
Automated control systems optimize plunger lift and well
unloading operations to prevent overloading (plunger
cannot overcome backpressure and rise to the surface) and
underloading (plunger rises to quickly, possibly damaging
equipment) therefore reducing or eliminating well venting.
"Smart" automated control systems combine customized
control software with standard well control hardware such
as remote terminal units (RTUs) and programmable logic
controllers (PLCs) to cycle the plunger system and lift
fluids out of the tubing. The artificial intelligence
component of a smart automation system monitors the
tubing and sales line pressures and allows the PLC to
"learn" a well's performance characteristics (such as flow
rate and plunger velocity) and to build an inflow
performance relationship (TPR) curve for the well. The
frequency and duration of the plunger cycle is then
modified to optimize well performance.
Data analysis combined with wellhead control technology
is the key to an effective gas well "smart" automation
system. A smart automation system stores historical well
production data allowing the program to learn from
experience by monitoring and analyzing wellhead
instrument data. The control system relays wellhead
Exhibit 4: Plunger Lift
Source: Chesapeake Energy
4

-------
Options for Removing Accumulated Fluid and Improving Flow in Gas Wells
(Cont'd)
instrument data to a central computer, tracks venting
times, and reports well problems and high-venting wells,
all of which allow custom management of field production.
The components of a smart well automation system that
must be installed on each gas well include:
*	remote terminal unit with PLC,
*	tubing and casing transmitters,
*	gas measurement equipment,
*	control valve, and
*	plunger detector.
Automated controllers at the wellhead monitor well
parameters and adjust plunger cycling. These typically
operate on low-voltage, solar batteries. Exhibit 5
illustrates typical wellhead equipment and telemetry for
plunger lift automated control systems. A host system
capable of retrieving and presenting data is also required
for continuous data logging and remote data transition.
Operators configure all controls and send them to the RTU
from the host system. Engineering time is needed to
customize the control software and optimize the system.
Field operating practices and protocols must be flexible to
quickly address well performance deficiencies and
operating problems.
Partners have found that optimized plunger lift cycling to
remove liquids can decrease the amount of gas ventfed by
up to 90+ percent. Methane emission savings from
reduced well venting is a significant benefit that can add
up to huge volumes when applied on a field or basin scale.
Exhibit 5: Typical Wellhead Equipment and
Telemetry for Automated Control Systems for
Plunger Lift
Sucker Rods
Tubing
Perforations'
Pump barrel
#2 (middle)
Barrel Stop (no-go)
Standing Valve
Exhibit 6: Diagram of a Sucker Rod Pump and
Pump Jack
Perforated Mud Anchor
Upper
Traveling
Valve
Rod Pump
Seating Nipple
Tubing Anchor
Pull Tube #1
(inner)
Pump barrel
#3 (outside)
Lower Traveling
Valve
Cup Type
Hold Down
Gas Anchor (Dip Tube)
Water Level
Source' BP	Source: S. Bumgardner, Advanced Resources International, inc.
5

-------
Options for Removing Accumulated Fluid and Improving Flow in Gas Wells
(Cont'd)
Rod Pumps and Pumping Units
A clownhole positive displacement, reciprocating rod pump
with surface pump unit can be deployed in the later stages
of a well's life to remove liquids from the wellbore and
maximize production until the well is depleted (Exhibit 6).
Pumping units can be installed when there is insufficient
reservoir pressure to operate a plunger lift. The units can
be manually controlled by the field pumper, or very low
volume wells may be operated with a timer.
Pumping units not only eliminate the need to vent the well
to unload fluids but also extend the productive life of a
well. Methane emissions can be further reduced by
operating pumping units with electric motors, rather than
natural gas-fueled engines. The annual fuel requirement
for a typical pumping unit is approximately 1,500 Mcf per
unit, of which 0.5 percent is emitted as unburned methane
(8 Mcf per unit per year).
A well workover rig is required to install the downhole rod
pump, rods, and tubing in the well. Field personnel must
be trained for rod pump operations and proper
maintenance of the surface equipment. Excessive wear of
the rods and tubing can be a major expense for rod pump
applications where solids are produced or down hole
corrosion is a problem.
A common problem with reciprocating pumps in gas wells
is gas locking of the rod pump valves, which prevents the
pump from delivering fluid to the surface at the design
rate. The presence of free gas in the subsurface sucker rod
pump decreases the volumetric pump efficiency and can
prevent the pump from lifting fluid. This is not a problem
found in progressive cavity pumps as there are no valves to
gas lock.
Economic and Environmental Benefits
Implementation of fluid removal options and artificial lift
provide economic and environmentally beneficial
alternatives to well blowdown. The major benefit of the
Four Steps for Evaluating Artificial Lift Options:
1.	Determine the technical feasibility of various artificial
lift options.
2.	Determine the cost of various options.
3.	Estimate the natural gas savings and production
increase.
4.	Evaluate and compare the economics of artificial lift
options.
various fluid removal options is extending the productive
life of a well. The full scope of environmental and
economic benefits depend on the type of artificial lift
system and the remaining productive capacity of the well.
Several benefits described below, are realized with the
progressive application of fluid removal options in gas
wells.
*	Improved gas production rates and extended
well life. Fluid removal and artificial lift systems
conserve reservoir energy and boost gas production.
Regular fluid removal generally extends the economic
life of declining wells resulting in more continuous
gas production, improved gas production rates, and
incremental ultimate recovery.
*	Reclaims vented gas to sales. Avoiding well
blowdown reclaims the value of gas that would
otherwise be vented to the atmosphere.
*	Reduced pollution. Eliminating well blowdown and
gas venting eliminates a significant source of
methane and other air pollutant emissions.
*	Lower well maintenance costs and fewer
remedial treatments. Overall well maintenance
costs can be reduced by eliminating the cost of a
workover rig for swabbing wells. Other savings occur
when well blowdowns are significantly reduced or
eliminated.
Decision Process
The decision to implement any type of liquid removal
option during the life-cycle of a gas well should be made
when the value of the estimated incremental gas
production exceeds the cost of the fluid removal option.
When one fluid removal approach becomes ineffective and
uneconomic, another can be deployed. If venting a well is
the current fluid removal approach, the application of
foaming agents, velocity tubing or plunger lift should be
evaluated before well blowdowns become too frequent, less
effective and costly. Natural Gas STAR Partners can use
the following decision process as a guide to evaluate the
application, safety, and cost effectiveness of fluid removal
and artificial lift installations.
Step 1: Determine the technical feasibility of a fluid
removal option or artificial lift installation.
Various data and criteria should be evaluated to select a
fluid removal approach that is both technically feasible
and cost effective. These data include IPR (inflow
6

-------
Options for Removing Accumulated Fluid and Improving Flow in Gas Wells
(Cont'd)
performance relationship) curves; reservoir pressure; gas
and fluid production flow rates; fluid levels in the well; the
desired flowing bottom hole pressure and casing pressure;
production tubing size, the downhole condition of the well;
other mechanical limitations of the well and production
site; and the capabilities and training of field personnel.
Appendix A (Exhibit A1 and A2) shows the Turner
relationship and Lee relationship between critical flow
rate (critical gas velocity), and flowing pressure for various
sizes of production tubing. If the relationship between
flow rate and pressure falls below a line specifying a size of
production tubing, a well will not flow liquids to the
surface for the indicated tubing size. If flow rate vs
pressure falls on or above the line for a specified tubing
size, a well meets or exceeds the critical flow rate for the
specified tubing size and the well is able to unload fluid to
the surface. Exhibits A1 and A2 can be used as starting
points to estimate whether a fluid removal or artificial lift
option is likely to be effective. Following are some
technical considerations that enter into the decision
process for each fluid removal option:
*	Foaming Agents. Partners typically use foaming
agents early in the life of gas wells when the wells
begin to load with formation water and the liquid
production rate is comparatively low. Foaming works
best if the liquid in the wellbore is mainly water, and
condensate content is less than 50 percent. Foaming
agents may also be used in combination with other
well treatments that reduce salt and scale build up,
or may be applied in combination with velocity
tubing.
*	Velocity Tubing. Velocity tubing strings are
appropriate for natural gas wells with relatively
small liquid production and higher reservoir
pressure. Low surface pipeline pressure relative to
the reservoir pressure is also necessary to create the
Indicators of Liquid Loading in Gas Wells:
1.	Construct an IPR curve and evaluate the production
efficiency of the well.
2.	Monitor production curves for each well on a regular basis.
Liquid loading is indicated if the curve for a normally
declining well becomes erratic and the production rate drops.
3.	Compute the critical gas velocity (flow rate) at which liquid
can no longer be lifted in the tubing (see Appendix)
4.	Critical velocity vs. flowing tubing pressure can be
constructed for various tubing diameters.
pressure drop that will achieve an adequate flow
rate. The depth of the well affects the overall cost of
the installation, but is usually offset by the higher
pressure and gas volume in deeper wells. Velocity
tubing can also be a good option for deviated wells
and crooked well bores. Rod pumped wells with
deviation and or dog legs that become uneconomic
due to high failure rates and servicing costs may also
be candidates for velocity strings.
Determining the feasibility of installing a velocity
tubing string is relatively straightforward. An
inflow performance relationship (IPR curve) is
calculated to establish the flow regime in the well
tubing, as shown in Exhibit 7. The diagram shown
in Exhibit 7 illustrates the relationship between gas
production and the bottom hole flowing pressure
(BHFP). Gas flow is evaluated and the velocity
relationships for various sizes of tubing are
developed to determine the appropriate diameter for
use in each well. As a rule of thumb, a gas flow
velocity of approximately 1,000 feet per minute is the
minimum necessary to remove fresh water.
Condensate requires less velocity due to its lower
density while more dense brine requires a higher
velocity.
Once the velocity string is installed, no other
artificial lift equipment is required until the
reservoir pressure declines to the point that
Exhibit 7: Example of Inflow Performance
Relationship Curve for Evaluating Fluid
Removal Options
3250
3000
2750
2500
2250
2000
1750
Q.
LL
1500
x
CO
1250
1000
750
500
250
o
o
o
o
o
o
o
o
o
o
o
o
o
o
o
o
o
o
o
o
o
Gas Production (Mcfd)
Source: S. Bumgardner, Advanced Resources International, inc.
7

-------
Options for Removing Accumulated Fluid and Improving Flow in Gas Wells
(Cont'd)
velocities of 1,000 feet per minute are no longer
possible in the tubing. The introduction of a foaming
agent to the bottom of a tubing string will extend the
effective life of a velocity string below the 1,000 feet
per minute velocity required to lift water by reducing
the density of the column that is lifted. This only
applies to water lifted from the well tubing since
condensate is not affected by a surfactant.
*	"Smart" Well Automation of Plunger Lift.
Candidate wells for plunger lift generally do not have
adequate downhole pressure for the well to flow
freely into a gas gathering system. Like pumping
units, plunger lifts are used to extend the productive
life of a well. Installation is less expensive than rod
pumps, but plunger lifts may be difficult to operate.
Conventional plunger lift operations rely upon
manual, on-site adjustments to tune a plunger cycle
time. When a plunger lift becomes overloaded, the
well must be manually vented to the atmosphere to
restart the plunger. A "smart" well automation
system enhances plunger performance by monitoring
parameters such as tubing and casing pressure, well
flow rate and plunger cycle frequency (travel time).
Data for each well are relayed to a host computer
where operators review the data and address any
performance deficiencies or operating problems. This
helps to optimize plunger lift performance, improve
gas production, and reduce well venting.
Optimum plunger lift performance generally occurs
when the plunger cycle is frequent and set to lift the
smallest liquid loads. Small liquid loads require
lower operating bottom hole pressure, which allows
for better inflow performance. As with velocity
tubing, a desirable velocity for a plunger to ascend in
tubing is in the range of 500 to 1,000 ft per minute.
~	Pumping Units. Rod pump installations for gas
wells can be costly to install and operate, but can
extend well life, increase ultimate recovery, increase
profits and reduce methane emissions. A rod
pumping application for gas wells must be carefully
designed to ensure trouble-free installation of the
pumping units, minimize installation costs, and
maximize operating cost savings by reducing
mechanical wear and the need for well servicing.
Technical considerations for a rod pump application
include the amount of pump capacity required, the
pump setting depth in the well, and the type and
Methane Content of Natural Gas
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
%
gravity of the fluid in the hole (brine, fresh water,
hydrocarbon, hydrogen sulfide, carbon dioxide, etc.).
These factors influence the components of a rod pump
installation, including rod pump materials, rod string
size and grade, pumping unit design, size of the
prime mover (motor), pump speed and stroke length.
Resources available for evaluating and designing rod
pump applications for gas wells include American
Petroleum Institute and various Society of Petroleum
Engineers publications; commercial pumping unit
vendors; and computer design models. In general,
rod pump installations for gas wells have lower fluid
volumes than for oil wells. Operating costs can be
minimized by correctly sizing the artificial lift and
pumping as slow as possible while maintaining a
pumped-off condition. The use of pump-off controllers
are also effective by matching the pump displacement
to the volume of fluid entering the well bore.
Step 2. Determine the cost of fluid removal options.
Costs associated with the various fluid removal options
include capital, start-up and labor expenditures to
purchase and install the equipment, as well as ongoing
costs to operate and maintain the systems.
*	Foaming Agents. Partners report upfront capital
and start-up costs to install soap launchers ranging
from $500 to $3,880 per well. Monthly cost for the
foaming agent is $500 per well, or approximately
$6,000 per year. As such, typical costs can vary
between $500 and $9,880.
*	Velocity Tubing. One Partner reports total capital
and installation costs of at least $25,000 per well,
which includes the workover rig time, downhole tools,
tubing connections and supervision. Another Partner
has deployed velocity tubing in more than 100 wells
and reports total installation costs ranging from
$8,100 per well to $30,000 per well. Based on Partner
experiences, typical costs will vary between $7,000
and $64,000 per well.
8

-------
Options for Removing Accumulated Fluid and Improving Flow in Gas Wells
(Cont'd)
*	"Smart" Well Automation of Plunger Lift. Two
Partners report implementing "smart" automation
systems to control plunger lift operations. One
operation is fairly small, consisting of 21 wells. The
second is a basin-wide deployment on more than
2,150 wells. Reported upfront costs for the smaller
installation is $6,300 per well. Total cost over 5 years
reported for the larger automation project is
$12,200,000 or approximately $5,700 per well.
Typical costs will vary between $5,700 and $18,000
depending on the complexity of the "smart"
automation system. These costs would be
incremental over the cost of installing a plunger lift
system.
*	Pumping Units. Capital and installation costs
include the use of a workover rig and crew, for
approximately one day, sucker rods, rod guides and
pump costs, and the cost of the pumping unit and
motor. Other start-up costs can include
miscellaneous clean out operations to prepare the
well to receive a down hole pump and sucker rods.
Partners report that location preparation, well clean
out, artificial lift equipment, and a pumping unit can
be installed for approximately $41,000 to $62,000 per
well. The reported average cost of the pumping unit
alone appears to range from approximately $17,000
to $27,000. Most companies have surplus units in
stock that can be deployed at the expense of
transportation and repair, or may purchase used
units.
Step 3. Estimate the savings from various fluid
removal options.
The total savings associated with any of the fluid removal
and artificial lift options include:
*	Revenue from incremental increased gas production;
*	Revenue from avoided emissions;
*	Additional avoided costs such as well treatment and
workover costs, and reduced fuel and electricity;
*	Salvage value.
Revenue from Increased Production
The most significant benefit of deploying foaming agents,
velocity tubing or a pumping unit is to extend the
productive life of the well by decreasing the abandonment
pressure of the reservoir and increasing the cumulative
gas production. The benefit of automating a plunger lift
system is to optimize the plunger cycle. Most of the
increase in gas production is realized by the initial decision
to install plunger lifts. Installing a 'smart' automated
control system provides some incremental increase in gas
production over a plunger lift system operated manually or
by a timer, but the most significant benefit is the
emissions avoided from repeated well blowdowns and the
reduction in personnel time required at the well.
The fluid removal options are evaluated based on the
incremental gas production predicted by well blowdowns.
For wells that are not on production decline, the
incremental gas production from installing velocity tubing
or artificial lift can be estimated by assuming the average
peak production after a well blowdown event represents
the incremental peak production that will be achieved
after the fluid removal option is implemented in the well.
The more common evaluation is for a well already
experiencing production decline. In such a case,
estimating incremental gas production from implementing
a fluid removal/ artificial lift method is more complex and
requires generating a new "expected" production and
decline curve that would result from reducing the back
pressure at the well perforations. This requires well-
specific reservoir engineering analyses, a basic example of
which is provided in Appendix B.
Once the incremental gas production from implementing a
fluid removal approach is estimated, operators can
Exhibit 8: Gas Production Increase from
Application of Foaming Agents
— One Partner's Experience
•	One Gas STAR Partner reports injecting foaming
agent into 15 wells using soap sticks.
•	Incremental gas production of individual wells
increased an average of 513 Mcf per well per year.
•	Annual incremental gas production for the entire
project was 7,700 Mcf.
•	Total cost for the project was $8,871 in 2010 dollars.
•	At nominal gas prices ranging from $3.00/ Mcf to
$5.00/ Mcf, the value incremental gas production
ranges from approximately $23,100 to $38,500/
year and project payback occurs in 3 to 5 months.
9

-------
Options for Removing Accumulated Fluid and Improving Flow in Gas Wells
(Cont'd)
calculate the value of the incremental gas and estimate the
economics of the application. Exhibit 8 is an example of
the potential revenue from increased gas production using
foaming agents. Note that Exhibit 8 does not include other
benefits such as avoided blowdown emissions and
operations cost savings.
Revenue from Avoided Emissions
Emissions from venting gas to the atmosphere vary in both
frequency and flow rates, and are entirely well and
reservoir specific. The volume of natural gas emissions
avoided by reducing or eliminating well blow-downs will
vary due to individual characteristics such as sales line
pressure, well shut-in pressure, fluid accumulation rate,
and well dimensions (such as depth and casing and tubing
diameters). Another key variable is an operator's normal
practice for venting wells. Some operators put wells on
automatic vent timers. Some wells are vented manually
with personnel standing by monitoring the blow-down. In
some cases, wells are open to vent and unattended for
hours or days, depending upon the time it typically takes
the well to clear liquids. The economic benefits of avoided
emissions will vary considerably, and some projects will
have significantly shorter payback periods than others.
Partner-reported annual emissions attributable to well
blowdowns vary from 1 Mcf per well to several thousand
Mcf per well, so methane emissions savings attributable to
avoided emissions will also vary according to the
characteristics and available data for the particular wells
being vented. Exhibit 9 illustrates the range of avoided
emissions reported by various Partners after applying
specific fluid removal and artificial lift strategies in their
operations.
Revenue from avoided emissions can be calculated by
multiplying the sales price of the gas by the volume of
vented gas. If well emissions have not been measured,
they can be estimated. The volume of emissions from well
venting can be estimated by constructing an IPR curve to
predict the open flow potential of the well based on
reservoir pressure, depth, tubular sizes, and fluid
constituents. Other operator methods are discussed in
Appendix C. The volume of gas released during well blow-
down is dependent on the duration of the event, wellhead
temperature and pressure, size of the vent line, the
properties of the gas, and the quantity of water produced.
Four approaches to estimating well blow-down emissions
are provided in Appendix C. None of the estimations
discussed in Appendix C provide the "exact" result in an
absolute sense, but they are accurate enough for effective
management of producing gas wells. One emission
estimation approach calculates well blow-down volume as
a function of venting time, normal production rate, well
volume and gas properties. Another approach uses
Exhibit 9: Comparison of Partner-Reported Costs and Emissions Savings for Fluid
Removal/Artificial Lift Options
Fluid Removal
Approach
Installation Costs
($/well)
Incremental Gas
Production
(Mcf/well/year)
Avoided Methane Emissions
from Swabbing/ Blowdown2
(Mcf/Well/Year)
Other Potential Cost
Savings
($/well)
Use Foaming Agents
$500 - $9,880
(installation of soap launcher);
$500/month (surfactant)
365 - 1,095
178 - 7,394
$2,000
(eliminate well
swabbing)
Install Velocity
Tubing
$7,000 - $64,000
9,125 - 18,250
146- 7,394
$2,000 - $13,200
(eliminate well
swabbing & blowdown)
"Smart" Well
Automated Controls
for Plunger Lift1
Partner reported average cost =
$5,700 - $18,000
Not reported by Partners
{5,000 Mcf estimated for
average U.S. gas well by
assuming a 10-20%
increase in production)
Partner reported =
630 - 900
(500 Mcf estimated
for average U.S. well by assuming
1 % of annual production)
$7,500
(reduces labor cost to
monitor plunger lift
installations in the
field)
Install Rod Pumps
and Pumping Units
$41,000 - $62,000
Not reported
769- 1,612
$22,994
(salvage value at end
of well life)
incremental cost, gas production and methane emissions savings for installation of automated plunger lift control system.
2Assumes methane content of natural gas at wellhead is 79 percent, unless reported otherwise.
10

-------
Options for Removing Accumulated Fluid and Improving Flow in Gas Wells
(Cont'd)
pressure transient analysis to extrapolate gas flow rate
from wellhead pressure. A final approach installs an
orifice meter on a vent line and measures specific vent
volume over time. The resulting vent rates expressed in
Mcf/minute are averaged by producing formation and
extrapolated from the initial subset of wells measured to
the larger well population.
Avoided Costs and Other Benefits
Avoided costs and additional benefits depend on the type of
fluid removal/ artificial lift system currently applied in the
well and the new system to be deployed. These can include
avoided chemical treatments, fewer well workovers, lower
fuel costs and lower daily operations and maintenance
costs. Partners report using foaming agents to replace well
swabbing for a savings of approximately $2,000 annually
per well. EPA's Natural Gas STAR Partners report that
"smart" well automated control systems for plunger lifts
have reduced the labor cost for field monitoring by
approximately $7,500 per well. Velocity tubing eliminates
well swabbing, well blowdowns and chemical treatments,
the cost of which are reported to range from a few
thousand to more than $13,000 per treatment.
Step 4. Evaluate the economics of fluid removal
options.
Basic cash flow analysis can be used to compare the costs
and benefits of the various fluid removal options. Exhibit
9 is a summary of the installation costs, gas savings and
reduced methane losses associated with each fluid removal
approach that have been reported by Natural Gas STAR
Partners. Cash flow analyses based on Partner-reported
experience and data are provided in Exhibit 10 for
installing velocity tubing strings and in Exhibit 11 for
"smart" well automated control systems for plunger lift.
Partner Experience
This section highlights specific experiences reported by
Gas STAR Partners with the selected fluid removal options
for gas wells.
Install Velocity Tubing Strings.
One Partner reported installation of velocity tubing in two
Gulf Coast wells during 2008. Total installation cost in
2008 was $25,000 per well, which included a workover rig
to remove and replace tubing, downhole tools, connections
and supervision. Due to low inflation between years 2008
and 2010, the installation cost in 2010 dollars is only
slightly higher than 2008.
The velocity tubing installation in these wells improved
gas production by 25 Mcfd to 50 Mcfd, which equates to
annual incremental gas production of approximately 9,125
Mcf to 18,250 Mcf per well. In addition, gas savings from
eliminating well swabbing is 160 Mcf per year per well.
Methane content of gas at the well head is 91 percent, so
the estimated reduction in methane losses are 146 Mcf per
well. Velocity tubing also eliminated annual swabbing
costs of approximately $2000 per well per year. Exhibit 10
Exhibit 10:
Economic Analysis of Velocity Tubing Installation Replacing Periodic Swabbing








YearO
Year 1
Year 2
Year 3
Year 4 Year 5

Value of Gas from
Increased Production1

$36,500
$36,500
$36,500
$36,500
$36,500

Value of Gas from
Avoided Emissions2

$640
$640
$640
$640
$640

Velocity Tubing
Installation Cost
($25,000)






Avoided Swabbing Cost
$2,000
$2,000
$2,000
$2,000
$2,000

Net Annual Cash Flow
($25,000)
$39,140
$39,140
$39,140
$39,140
$39,140





Internal Rate of Return
NPV (Net Present Value)3=
Payback Period =
= 155o/o
$112,156
8 months

1 Gas valued at $4.00/ Mcf for 9,125 Mcf/well (25 Mcfd) due to increased gas production
2Gas valued at $4.00/Mcf for 160 Mcf/well of avoided gas emissions due to elimination ofwell swabbing
3 Net present value based on 10 percent discount rate over 5 years



11

-------
Options for Removing Accumulated Fluid and Improving Flow in Gas Wells
(Cont'd)
provides a cash flow analysis of this Partner's velocity
tubing installation replacing well swabbing.
Install "Smart"A utomated Control Systems on
Plunger Lifts
Two Partners have applied "smart" well automated
control systems at plunger lift installations. One Partner—
BP—initiated an automation project in 2000, and in 2001
began installing automated plunger lift control systems
across their San Juan Basin operations. BP justified the
project based on gas and methane emissions savings
resulting from a 50 percent reduction in well venting
between 2000 and 2004. By 2007, BP implemented
automated control systems for more than 2,150 wells
equipped with plunger lift which resulted in average
methane emissions savings of 900 Mcf per well. Total cost
for the "smart" automation systems was $12.2 million.
Total gas venting was reduced from approximately 4
billion cubic feet of gas per year (Bel) to approximately 0.8
Bcf.
Another Natural Gas STAR Partner found that a
substantially smaller application of "smart" automated
controls for plunger lift can be similarly effective. An
automated control system was implemented for 21 wells
equipped with plunger lifts. Total gas savings are 16,800
Mcf per year, or 800 Mcf per well. Assuming a methane
content of 79 percent, estimated annual methane
emissions savings are 632 Mcf per well.
The wide range in upfront capital and installation costs for
components of plunger lift automated control systems are
indicated in Exhibit 9. The host computer and
communication system can be quite costly ($50,000 to
$750,000) depending upon the size of the project, but as
more plunger lift-equipped wells are added, the unit cost
for the automated control system is significantly reduced.
The two Natural Gas STAR Partners report approximate
unit costs for plunger lift automated control systems of
$6,800 and $5,950 per well, respectively. Exhibit 11
provides a basic cash flow analysis of "smart" well
automated control systems for plunger lift based on
Exhibit 11: Economic Analysis of "Smart" Well Automated Control Systems for Plunger
Lift for Hypothetical Onshore Gas Field1








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

Value of Gas from Increased
Production2
$220,000
$220,000
$220,000
$220,000
$220,000

Value of Gas from Avoided
Emissions3
$40,000
$40,000
$40,000
$40,000
$40,000

Install RTUs at Wells, $
($ll,000/well x 20 wells)
($220,000)





Install Host Computer/
Communication
($50K - - $750K)
($200,000)





Avoided Labor Cost for Field
Monitoring
($7500/well x 20 wells)
$150,000
$150,000
$150,000
$150,000
$150,000

Net Cash Inflow
($420,000) $410,000
$410,000
$410,000
$410,000
$410,000




Internal Rate of Return = 94%
NPV (Net Present Value)4= $1,031,111
Payback Period = 12.3months
1	Assumes production from average US gas well is 50,000 Mcf/Year
2	Gas valued at $4.00/Mcf for 5,000 Mcf/well of increased gas production due to optimized plunger lift operation; equivalent to 10% of production for average US onshore
gas well. Assumes 20 wells in project.
3	Gas valued at S4.00/Mcf for 500 Mcf of gas savings due to reduced well blowdown/venting; equivalent to 1 % of production for average US onshore gas well. Assumes
20 wells in project.
4	Net present value based on 10 percent discount rate over 5 years
12

-------
Options for Removing Accumulated Fluid and Improving Flow in Gas Wells
(Cont'd)
generic assumptions about potential increased gas
production and methane emissions savings for the average
onshore natural gas well in the United States.
Install Pumping Units on Wells Lifting Low Water
Volumes
ConocoPhillips installed pumping units on 45 low-pressure
gas wells in 2003 to remove low water volumes from the
wells and prevent them from loading up. This installation
eliminated routine venting of the wells for up to one hour
per day. The primary benefit of installing pumping units
on these wells is the incremental gas production gained by
extending the productive life of the wells. The Partner
reported gas savings of 973 Mcf per well from the
elimination of well blowdowns as a secondary, but not
insignificant, benefit. The pump jacks at this installation
are powered by electric motors rather than natural gas
engines, which contributes to fewer methane emissions
and lower maintenance costs.
ConocoPhillips reported total gas savings of 43,780 Mcf for
the project or approximately 973 Mcf per well per year. At
a nominal gas price of $4.00 to $5.00/Mcf, this corresponds
to savings of approximately $3,892 to $4,865 per unit, or
$175,140 to $218,900 per year for the entire project
consisting of 45 wells. Assuming a methane content of 79
percent, this project has reduced methane losses by 34,586
Mcf per year.
Total capital and installation costs for the downhole
pumps and surface pumping units were estimated to be
$62,000 per well in 2003 or the equivalent of $73,332 in
2010 dollars. The total cost in 2003 included $45,000 for
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.
site preparation, downhole equipment, and installation
plus an average cost of $17,000 per pumping unit. The
project was expanded in subsequent years. ConocoPhillips
reported a total of 100 pumping units installed from 2005
through 2007. During this time, the average reported
upfront installation cost declined to approximately $38,000
per unit in 2010 dollars. Assuming a nominal gas price of
$4, the vented gas savings alone pays back the typical
pumping unit installation for this project in less than 10
years.
Lessons Learned
*	For natural gas wells, a progression of fluid removal
options are available to unload accumulated fluid,
boost gas production, extend well life and reduce or
eliminate the need for well venting.
*	Options for removing accumulated wellbore fluids
from gas wells range from relatively low cost
application of surfactants, appropriate for wells with
low fluid production and significant remaining
reservoir energy, to installing pumping units and
downhole rod pumps on wells with depleted reservoir
pressure and significant water production.
*	The best approach will depend on the where a well is
performing along the continuum of its productive life.
*	Well blow down and swabbing can release large
volumes of natural gas to the atmosphere, producing
significant methane emissions and gas losses.
*	Fluid removal approaches presented in this paper
can reduce the amount of remedial work needed
during the lifetime of a well, eliminate well
blowdowns, and increase the ultimate recovery of the
well while minimizing methane emissions to the
atmosphere.
*	If a well is in production decline, the fluid removal
alternatives discussed here will increase gas
production in most cases or at least arrest the
decline.
*	This increased gas production should be captured in
analyses of cash flow and future economic benefit
when evaluating fluid removal options for gas wells.
In most cases, increased gas production is the
primary benefit from implementing any or all of the
fluid removal options.
13

-------
Options for Removing Accumulated Fluid and Improving Flow in Gas Wells
(Cont'd)
~ Methane emissions and gas savings from the
elimination of well venting is generally a secondary,
but significant, benefit, which may cover all or most
of the upfront installation costs for a fluid removal
technology.
References
Advanced Resources International, 2004, Review and Selection of Velocity
Tubing Strings for Efficient Liquid Lifting in Stripper Gas Wells, Final
Technical Report, May 31, 2004, U.S. Department of Energy, National
Energy Technology Laboratory, Contract DE-FC26-00NT41025.
Barry, D., 2009, Liquid Loading, ABB Total Flow presentation, May 11,
2009; http://www.afms.org/Docs/liquids/LiquidLoad.pdf
BP, 2009, Well Venting and Completion Emission Estimation, 2009 Natural
Gas STAR Annual Workshop, San Antonio, TX.
BP, 2006, Plunger Well Vent Reduction Project, 2006 Natural Gas STAR
Workshop
Brandywine Energy and Development Co., 2002, Design Development and
Well Testing of a Prototype Tool for in Well Enhancement of Recovery
of Natural Gas via Use of a Gas Operated Automatic Lift Pump,
October 2002, U.S. Department of Energy, National Energy
Technology Laboratory, Contract DE-FC26-00NT41025
Christiansen, R. L., 2006, A New Look at Foam for Unloading Gas Wells;
Final Report, September 1, 2004 to December 31, 2005, DOE
Contract DE-FC26-00NT42098, Pennsylvania State University, June
2006.
Dake, L.P. 1978, Fundamentals of Reservoir Engineering, First Edition,
Elsevier, Great Britain
Devon Energy, 2006, Opportunities for Methane Emissions Reductions
from Natural Gas Production, presentation to Producers Technology
Transfer Workshop, Fort Worth, TX, June 6, 2006.
Elmer, B., and Gray, A., 2006, Design Considerations When Rod Pumping
Gas Wells, Lufkin Automation, available atwww.lufkinautomation.com.
Ghareeb, M., Frost, B., Tarr, C. and Sadek, N., 2008, Application of Beam
Pumping System for High Gas/Oil Ratio wells, Middle East Artificial
Lift Forum, Bahrain, February 16-18, 2008
McAllister, E.W. 1998, Pipe Line Rules of Thumb Handbook, Fourth
Edition, Gulf Publishing Company, (pp. 282-284).
Petroleum Technology Transfer Council, 2005, Gas Field Technology,
Solutions from the Field newsletter, April 28, 2005, 4 pp.
Smarter clocks automate multiple well plunger lift, Oil & Gas Journal,
August21, 2006, volume 104, issue 31.
Turner, R.G. et al., 1969, Analysis and prediction of minimum flow rate for
the continuous removal of liquids from gas wells, Journal of Petroleum
Technology, vol. 21, no. 11,Nov 1969, pp. 1475-1482.
United States Environmental Protection Agency, 2010, Inventory of U.S.
Greenhouse Gas Emissions and Sinks, 1990—2008, U.S. EPA #430-
R-10-606 (April 2010).
Wells, M., 2003, Gas Well Deliquification, Elsevier, USA
14

-------
Options for Removing Accumulated Fluid and Improving Flow in Gas Wells
(Cont'd)
APPENDIX A: Estimating the Critical Flow Rate
to Remove Liquids from Production Tubing
Source: S. Bumgardner, Advanced Resources International, inc.
APPENDIX B: Estimating Incremental Production
for Declining Wells
From Dake's Fundamentals of Reservoir Engineering
(1978) the following analytical model can be used to
estimate increased gas flow into a well in response to
reducing back pressure on the perforations by removing
accumulated liquids. The semi-steady state inflow
equation is:
m(Pavg)-m(pWf)=[(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 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
Incremental production achieved by implementing various
artificial lift options can be estimated by solving this
equation for SQ' calculated for retarded flow with fluids in
the hole (current conditions and current decline curve),
and comparing to *Q' calculated for the condition of no
fluids in the hole (artificial lift active and improved decline
curve). This discussion is intended as a guide for
estimating the potential impact of fluid removal
alternatives, and is not a substitute for thorough reservoir
engineering analyses of specific wells.
Exhibit A2: Lee Unloading Rate for Well
Producing Water
O
(/>
1200
1000
Lee—Flat Droplet Theory
¦tM$6"l!%11.751
2 3/8" 1.995
•22/8/8" 1.9951.995
2 7/8" 2.441
2.99^-992
.E 200
200 400 600 800
Wellhead Flowing Pressure, psia
1,000
Exhibit Al: Turner Unloading Rate for Well
Producing Water
o
(ft
O)
ns
2500
2000
1500
£ 1000
E
3
I 500
Turner—Spherical Droplet Theory
0 ?
	rl/'lb" l./b'l—l—
-*-32»T6»1.751
2 7/8" 2.441
^$251.995
2.4412.441
-.-33^/2" 2.992.992












y









200 400 600 800
Wellhead Flowing Pressure, psia
1,000
Source: S. Bumgardner, Advanced Resources International, inc.
15

-------
Options for Removing Accumulated Fluid and Improving Flow in Gas Wells
(Cont'd)
APPENDIX C: Alternate Techniques for
Estimating Avoided Emissions When Replacing
Blowdowns
Simple Vent Volume Calculation
A conservative estimate of well venting volumes can be
made using the following equation:
Annual Vent Volume, Mscf/yr = (0.37x10"6)*(Casing
Diametei^nWell Depth )*(Shut-in Pressure)*# of Annual
Vents)
Where, casing diameter is in inches, well depth is in feet
and shut-in pressure is in psia. If the shut-in pressure is
not known, a suitable surrogate is the casing pressure at
the surface.
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, 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 sales line pressure.
Partners can estimate the minimum time needed 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
a Partner's practice is to open and vent the wells for a
longer time than calculated by these methods, the Annual
Vent Volume calculated by this equation can be scaled up
according to the ratio of the actual vent time versus the
minimum vent time calculated using the Weymouth
equation.
Natural Gas STAR Partner, BP, has reported three
approaches to estimating well venting and completion
emissions, which include: 1) a more detailed version of the
vent volume calculation method above, 2) pressure
transient analysis, and 3) installing an orifice meter on the
vent line.
Detailed Vent Volume Calculation
The detailed vent volume calculation is a function of
venting time, normal production rate, and "well blowdown
value" that represents the volume of gas in a well under an
assumption of line pressure.
Vent Volume(Mcf) =
((Vent Time - 30 min)*(1/1440)* Production Rate) + (Well
Blowdown Volume)
Well Blowdown Volume (Mcf) =
(well depth*3.1416*(casing diameter/2)2) * ((tubing press +
atmospheric press)/14.7) * (520/(Temp+460))/Z/1000
Variables:
•	production rate, Mcf per day
•	well depth, ft
•	atmospheric pressure, psia
•	shut-in tubing pressure, psig
•	temperature of gas in pipeline, °F
•	diameter of production casing, ft
•	compressibility, Z
A limitation of the vent volume calculation method is that
it does not account for either the volume or weight of a
column of fluid in the wellbore at the time of venting.
Pressure Transient Analysis
This method is based on observations of wellhead pressure
versus flow rate for a specific set of wells which are used to
develop a linear expression of gas flow rate versus
wellhead pressure. This relationship is then applied to
pressure transient data during blowdown to extrapolate
Mcf versus time for the venting period. All data are
evaluated using pressure data analysis software to
extrapolate total vented volumes based on the blowdown
time, pipe diameter and the decline in well head pressure
during the process. An advantage of this approach is that
it accounts for choke flow and is tailored to specific wells.
Limitations of the approach are that it fails to account for
very large influx into the reservoir and the observations
data set may not be representative of the formation. To
make the data set more representative, it is recommended
that the data include at least one point within the
following 5 ranges:
*	P < 25 psia
*	25 psia < P < 60 psia
16

-------
Options for Removing Accumulated Fluid and Improving Flow in Gas Wells
(Cont'd)
*	60 psia < P < 110 psia
*	110 psia < P < 200 psia
*	200 psia < P
Orifice Metering of Blow Down
For this approach, an orifice meter is installed on a vent
line and flow rates are measured directly during
blowdown. An advantage of this approach is the precision
of the data that are obtained, potentially offering
meaningful comparisons of vent volumes between well
types, well completions or producing formations.
A limitation of the approach is that results obtained from a
'study population' or small subset of producing wells will
likely be extrapolated to a larger field or producing area,
and the original study wells may not be representative of
field operations as a whole.
17

-------
Options for Removing Accumulated Fluid and Improving Flow in Gas Wells
(Cont'd)

£
s
33
O
\
rA
PRO^
(D
United States
Environmental Protection Agency
Air and Radiation (6202J)
1200 Pennsylvania Avev NW
Washington, DC 20460
2011
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.
18

-------