Lessons Learned 

from Natural Gas STAR Partners 

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 “blowdown”), which produces 

substantial methane emissions. The U.S. Inventory of 

Greenhouse Gas Emissions and Sinks 1990—2008 

estimates 9.6 billion cubic feet (Bcf) 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. 

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) 

Implementation 

Cost1 

(2010 $/Well) 

Project Payback (years) 

$3 per Mcf $5 per Mcf $7 per Mcf $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 

1Based on results reported by Natural Gas STAR Partners 

2Does not include incremental gas production. Includes only potential gas savings from avoided well venting. 

3 to 10 

Economic and Environmental Benefits 

1 
 

 

Options for Removing Accumulated Fluid and Improving Flow in Gas Wells 

(Cont’d) 

By avoiding or reducing well blowdowns, Partners report 

annual methane emissions savings that range from 500 

thousand cubic feet (Mcf) 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 liquid 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. 

Exhibit 2: Soap Stick Launcher with 

Automatic Controller 

Launch Button 

Access	 Supply Gas 

Regulator
 

Supply Gauge 

Drip Pot Junction Box 

Vent Valve Pressure 

Transducer 

Bypass, 

Equalizer 

Actuated 

Valve 

Valve 

Controller 

Gas Flow 

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 

PerforationPerforations 

Wellbore Liquids 

Float Shoe 

Source: S. Bumgardner, Advanced Resources International, inc.

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. 

Exhibit 4: Plunger Lift 

The operation of a plunger lift system relies on pressure

buildup in a gas well during the time that the well is shutin (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 blowdown) 

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 (IPR) 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 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 

Exhibit 5: Typical Wellhead Equipment and 

Telemetry for Automated Control Systems for 

Plunger Lift 

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 vented 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 6: Diagram of a Sucker Rod Pump and 

Pump Jack 

Perforations Sucker Rods 

Tubing 

Rod Pump 

Tubing Anchor 

Perforated Mud Anchor 

Water Level 

Gas Anchor (Dip Tube) 

Seating Nipple 

Pull Tube #1 

(inner) 

Upper 

Traveling 

Valve 

Cup Type 

Hold Down 

Pump barrel 

#2 (middle) 

Standing Valve 

Barrel Stop (no-go) 

Lower Traveling 

Valve 

Pump barrel 

#3 (outside) 

Plunger 

Source: S. Bumgardner, Advanced Resources International, inc. Source: BP 

5 
 

 

 

 

 

 

Options for Removing Accumulated Fluid and Improving Flow in Gas Wells 

(Cont’d) 

Rod Pumps and Pumping Units 

A downhole 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 

0 

250 

500 

750 

1000 

1250 

1500 

1750 

2000 

2250 

2500 

2750 

3000 

3250 

0

100200300400500600700800900

1000 

Gas Production (Mcfd) 

BHFP (psia) 

Exhibit 7: Example of Inflow Performance 

Relationship Curve for Evaluating Fluid 

Removal Options 

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 

The average methane content of natural gas varies by natural gas 

industry sector. The Natural Gas STAR Program assumes the 

following methane content of natural gas when estimating 

methane savings for Partner Reported Opportunities. 

Production 79 % 

Processing 87 % 

Transmission and Distribution 94 % 

Methane Content of Natural Gas 

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 wellspecific 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 blowdown 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) 

1Incremental 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 

Year 0 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 = 155% 

NPV (Net Present Value)3

= $112,156 

Payback Period = 8 months 1 Gas valued at $4.00/ Mcf for 9,125 Mcf/well (25 Mcfd) due to increased gas production 2 Gas valued at $4.00/Mcf for 160 Mcf /well of avoided gas emissions due to elimination of well 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’’ Automated 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 (Bcf) 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, $ 

($11,000/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 $4.00/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 blowdown 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 at www.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, 

August 21, 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 

Exhibit A1: Turner Unloading Rate for Well 

Producing Water

Turner—Spherical Droplet Theory 

2500 2 1/16" 1.751 

 2 1/16" 1.751 2 3/8" 1.995 2-1/16” 1.751 

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: 

Minimum Fluid Lift Rate, Mscfd 

2 7/8" 2.441 

3 1/2" 2.992 2 3/8" 2-3/8” 1.995 1.995 2000 

m(pavg)-m(pwf)=[(1422 x Q x T)/(k x h)] x [ln(re/rw)-3/4+S)] 

2 7/8" 2.441 2-7/8” 2.441 

3 1/2" 2.992 3-1/2” 2.992 Where, 1500 

x (8.15) 

 m(pavg) = real gas pseudo pressure average 

1000 

 m(pwf) = real gas pseudo pressure well flowing 

Q = gas production rate 

T = absolute temperature 

500 

0 

0 200 400 600 800 1,000 k = permeability

Wellhead Flowing Pressure, psia h = formation height 

Source: S. Bumgardner, Advanced Resources International, inc. 

re = external boundary radius 

Exhibit A2: Lee Unloading Rate for Well rw = wellbore radius Producing Water 

S = mechanical skin factor 

Lee—Flat Droplet Theory 

Incremental production achieved by implementing various 1200 

 2 1/16" 1.751 artificial lift options can be estimated by solving this 2 1/16" 1.751 2-1/16” 1.751 equation for `Q' calculated for retarded flow with fluids in 2 3/8" 1.995 

1000 2 3/8" 2-3/8” 1.995 1.995 the hole (current conditions and current decline curve), 2 7/8" 2.441
 

2 7/8" 2.441 2-7/8” 2.441 
 and comparing to `Q' calculated for the condition of no 3 1/2" 2.992 

800 fluids in the hole (artificial lift active and improved decline 3 1/2" 2.992 3-1/2” 2.992 

curve). This discussion is intended as a guide for 

estimating the potential impact of fluid removal 600 

alternatives, and is not a substitute for thorough reservoir 

engineering analyses of specific wells. 400 

200 

0 

0 200 400 600 800 1,000 

Wellhead Flowing Pressure, psia 

Source: S. Bumgardner, Advanced Resources International, inc. Minimum Fluid Lift Rate, Mscfd 

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 

Diameter2

)*(Well 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 backpressure 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, oF 

 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) 

United States 

Environmental Protection Agency 

Air and Radiation (6202J) 

1200 Pennsylvania Ave., 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