This covers such topics as what is liquid loading, how does it inhibit gas production, when is some form of artificial lift required?
According to the EIA:
( http://tonto.eia.doe.gov/dnav/ng/ng_prod_wells_s1_a.htm
, http://tonto.eia.doe.gov/dnav/ng/hist/n
9011us2A.htm
)
The US gas well count was 448,641 in 2006 with the annual gas production being 17,942,493
MMscf. According to these figures, the average gas rate per well is about 110 Mscf/D. Considering the critical rate for liquid loading for 2 3/8’s inch ID tubing with 100 psia on the wellhead is about 300 Mscf/D, it would appear that many gas wells are liquid loaded. However loading is not limited to low rate producers as large diameter tubing wells load at a much higher rate.
Comparably there are about 500,000 oil wells producing about 10 bpd.
( http://www.eia.doe.gov/emeu/aer/pdf/pages/sec5_7.pdf
).
Liquid loading is defined in various ways. Some Gas Production Operators say a well is suffering from liquid loading when its gas production rate has fallen sharply off its established decline curve and stays there. However, this change or indication will not occur if the well has been liquid loaded for its entire life.
Other symptoms that may indicate liquid loading include:
•
The well will show an increasing difference between casing and tubing pressure as it loads.
•
Slugging may occur at the well head, upstream of any liquid knock-out device or separator, when this has not occurred before.
•
A wireline pressure survey or sonic fluid level shot down the tubing while the well is producing gas shows the existence of a gassy liquid level in the tubing.
•
A clear indication of liquid loading occurs when a well is still flowing, but at a lower, more erratic rate than normal.
Turner 1 and later Coleman 2 characterized loading as occurring when droplets of liquid in the tubing either rise (not loaded) or fall against the flow (loaded). They balanced the weight of liquid droplets vs. the upward drag force from the flow of gas. The gas production velocity and corresponding rate to just support the droplets and keep them from falling and accumulating in the bottom of the well is referred to as the critical velocity or rate.
The Turner Equation for calculating the minimum gas velocity required to sustain flow in the presence of liquid droplets (critical velocity) is shown below. This is correlated to well data with surface pressures generally well above 1000 psi.

υ 
1.92
σ
1
4

ρ
L
 ρ g

1
4
ρ g
1
2

Minimum gas velocity in units of

Surface tension in units of
L

Liquid phase density in units of lbm ft
3
ρ g

Gas phase density in units of lbm ft
3
The following assumptions are commonly used to place the equations into a more fieldusable graphical form:
Surface tension,
of condensate is 20
and that of water is 60
Liquid phase density,
L of condensate is 45 lbm
and that of water is 67 ft
3 lbm ft
3
Gas gravity is 0.6 and gas temperature is 120 o
F.
Often a gas compressibility or Z factor of 0.9 is used; but in the graph below, it is calculated as a function of gas gravity, pressure, and temperature.
The equation can be expressed as a function of pressure, where p is in units of psia .
WATER





1
2

1
4
υ
CONDENSATE

4.02

45

0.0031p

0.0031p

1
2

1
4
When water and condensate are both present, use the water equation.
When the flow rate is above the critical velocity, Turner predicts that liquid droplets are being carried up by the gas velocity and are not accumulating in the well. If the flow rate is below the critical velocity, Turner predicts that droplets are not being carried upward and are accumulating in the well. The well may or may not cease to produce even if the gas velocity is below the critical rate, but flowing below the critical rate will decrease the gas production rate.
Using the Turner velocity equation for water, and the assumptions stated above, a chart for critical rate for various tubing sizes (Figure 1) can be constructed.

3000
2500
2000
4-1/2 OD 3.958 ID
3-1/2 2.992
2-7/8 2.441
2-3/8 1.995
2-1/16 1.751
1500
1000
500
0
0 50 100 150 200 250 300 350 400 450 500
Flowing Pressure (psi)
Figure 1: Critical Rates according to Turner 1 for water
The chart shows that for 100 psi wellhead pressure, and 2 3/8 ’s tubing, the well must flow approximately 320 Mscf/D or liquid loading will be predicted to occur. Similar charts can be constructed for condensate. When both condensate and water are present, use the water chart as water must still be removed. Charts for coiled tubing can also be constructed using this technique.
Coleman 2 , et al., correlated with well production data at lower well head pressures. Coleman predicts that a 20% lower flow rate than Turner is required to stay above the critical rate. Critical velocity or rate is a simple approximate method and may cause problems if applied universally. The Coleman correlation resulted from data for wells with lower WHP’s than those tested by Turner.
The Turner or Coleman equations, and observation of field symptoms, can be used to diagnose a well to check for liquid loading. If a well is loaded and the problem can be solved, a substantial production increase can often be achieved by returning the well to its original decline curve.
Note that most critical velocities or rates are computed at the wellhead pressure, as it is available. However, higher critical rates would be calculated if a pressure at the bottom of the

flowing well were to be used in a critical velocity calculation. Also the amount of liquid production is not considered in the critical velocity models. These and other considerations make this an approximate but useful method of analysis.
Nodal Analysis TM (Macco Schlumberger) modeling of gas wells can also indicate liquid loading tendencies, but requires more well and fluid data to make the analysis.
The industry uses a number of methods to remove liquid from (deliquify) gas wells. Research and development are constantly being preformed to make these methods more effective and to develop new methods.
Introductory comments on some of the commonly-used methods for gas well deliquification are listed here. Section 2.2 provides guidelines to help with selection of many of the methods of artificial lift used for deliquification. Section 2.4 and the several sub-sections which follow it provide specific detailed information on each of the methods that are used.
When a well first begins to show signs of liquid loading, this may be addressed by temporarily stopping and re-starting (cycling or intermitting) production. During the shut-in period the well pressure recovers (increases) around the well bore and some liquids may be forced back into the formation, thus reducing the liquid load (level) in the wellbore. Then the well is returned to production and allowed to flow until the loading again occurs and reduces the gas production rate.
This method is sometimes used if the well has just started to experience liquid loading and is waiting for some type of artificial lift system to be installed. It may also be used if the well has a packer. The packer may reduce the effectiveness of some artificial lift methods. It may need to be removed, if possible.
This method may have a serious drawback. In some formations, the presence of water can damage or reduce the permeability for gas. So, in this case, it may damage the well to push
(re-inject) water back into the formation.
However the method is inexpensive and it can work with a packer in place. Therefore, it is commonly used as an interim method of production before an artificial lift system can be installed.
Installing a smaller tubing size may be a solution in a loaded well. Figure 1 shows that for smaller tubing sizes, a lower production rate is required to operate above the critical flow rate.
Smaller tubing may work well if it isn’t too small. There are many good case histories. Very small tubing can be hard to unload and a small amount of liquid will stand high in the tubing and exert a high back-pressure on the formation.
Later in the well’s life, even smaller tubing may be required as the reservoir depletes. For wells with larger tubing that experience loading, smaller velocity strings are often used to return the well to production above the critical rate. Nodal Analysis can be very useful in analyzing this situation.

Compression is often used to lower the flowing wellhead pressure. This may be accomplished by a single wellhead compressor (to achieve lower pressures) or by a field-wide compression system. Reciprocating compressors, screw type compressors, and other types are used. It could be that below approximately 100 psi wellhead pressure, single well compression may be more effective considering line losses, etc.
By reducing the wellhead pressure to a lower level, more water is maintained in the vapor state, thus reducing the volume of water droplets to be produced. The lower wellhead pressure translates to lower formation pressure and more gas inflow rate into the wellbore. Lower pressure wells experience the highest percent increase in gas production rate with compression.
Before installing compression, check the possibility of using a larger flowline or a twin or parallel flowline to lower the wellhead pressure. Compression may be used to kick a well off if it is weak. But lower pressure may not be enough to restart a shut-in well that is loaded.
Compression helps most other types of artificial lift systems to work more effectively.
Plunger systems utilize a physical plunger or pig that travels from the bottom of the well to the surface. At the bottom of the well, the pressure must build enough to lift the plunger and liquid that has accumulated above the plunger to the surface. At the top of the well, a flow period of gas is established.
MASTER
VALVE
BLEED
VALVE
LUBRI CATOR
FLOW TEE
W/O-RI NG
BYPASS
VALVE
CATCHER
W/ARRIVAL
SENSOR
PLUNGER
MOTORIZED
VALVE
EXTERNAL
CABLE
BUMPER SPRING
TUBING STOP
ELECTRONIC
CONTROLLER

Figure 2: A typical conventional plunger lift installation.
Plunger lift is a preferred method by many Gas Production Operators. Conventional plunger lift may work if the well produces a gas/liquid ratio (GLR) of 400 Scf/bbl or greater and the casing pressure will build to 1 ½ times the line or separator pressure in a reasonably short time.
Plunger operation may be classified as conventional plunger lift ( maybe 90+% of applications) and free cycle plunger lift where the well flows all the time except for a brief shut-in time at the surface to allow the plunger or part of the plunger system to fall against the flow.
Figure 3 shows a conventional plunger cycle:
A B C D E
Figure 3: A conventional plunger cycle
A- Plunger at bottom with some liquid above plunger. Surface valve closed.
B- Surface valve opens and plunger rises with liquid above it.
C- Well flows at high rate for a while
D- Well begins to liquid load
E- Well shut in for plunger to fall through (1) gas and (2) liquid. A pressure build up period is controlled if needed.
Plungers used for this cycle include brush plungers, grooved plungers, wobble washer plungers, padded plungers, and other special types.

Figure 4 shows a free-cycle plunger cycle or continuous plunger cycle. It can be achieved by use of a two piece plunger as below or other contained ball and seat or contained valve type plungers.
A B C D E
A B C D E
Figure 4: A “free cycle” or “continuous flow” plunger cycle operation.
This figure shows a two-piece plunger (sleeve and ball) but this cycle could also work with a valved plunger such as the Weatherford RapidFlo TM Plunger, the FB FreeCycle TM Plunger, the McClain TM Plunger, or as shown above, the Pacemaker TM (two-piece) plunger. Other plungers that are not mentioned here may also work on this cycle.
A- The plunger is sealed by the ball at the bottom of a sleeve or a valve is closed in the plunger. It is carrying up a slug of liquid with the surface valve open.
B- The plunger arrives at the surface. If the two-piece plunger is used, the sleeve is held on a receiving rod and the ball falls against the flow. If a valve-type plunger is used, the plunger is held on a receiving rod with the flow.
C- The gas continues to flow with the sleeve of the two-piece plunger at the surface or with the RapidFlo, FreeCycle, or McClain plunger held by flow at the surface with production continuing. If the two-piece plunger is used, the ball can fall as the flow continues.
D- After a short shut-in period of perhaps 10-20 seconds, the sleeve of the two-piece plunger falls while gas flow continues. The entire plunger will fall if the RapidFlo,

FreeCycle, or McClain plunger is used. When the sleeve of the two-piece Pacemaker joins the ball at the bottom of the tubing, the plunger is sealed and with flow continuing, the ball and sleeve immediately start back up the tubing. When the RapidFlo,
FreeCycle, or McClain plungers hit bottom, a valve is closed, the plunger is sealed, and they start back up the tubing as flow continues. If the plunger falls too soon, an
Autocatcher may be installed to hold the plunger longer at the surface.
E- The sealed continuous flow plunger is rising with the flow with a slug of liquid being carried.
A
Figure 5:
A B C
A: Conventional grooved, padded and brush plungers
B: Two-piece plunger
C: Continuous RapidFlo Plunger
Other plunger techniques for weaker wells include progressive plunger lift (one plunger running over an upper portion of the well and another plunger running over a lower portion of the well). Also Casing Plungers may be used for weak wells with the plunger sealing in the casing and with the tubing removed (mostly in 4/1/2 casing).
For analysis of plunger operation the Echometer Plunger Lift analysis system allows one to monitor the travel of the plunger downhole without well intervention. The Smart Plunger
(PCS, Denver) contains an instrumented insert to capture data when the plunger is running.
The most common type of pumping system is the beam pump. Pumping systems typically pump liquid up the tubing and allow gas to flow up the casing/tubing annulus. Other pumping systems include electrical submersible pumps (ESP), progressing cavity pumps (PCP), hydraulic pumps (reciprocating and jet), and other novel pumps. The ESP and PCP systems can be configured so the pump can be replaced without pulling the tubing. This is refereed to as the TTC (through tubing conveyed) system offered by Centrilift Hughes.

Problems with pumping systems can be sand and gas production. The PCP is designed to handle some sand with reduced wear and gas interference. If the pump is landed below the perforations, then good gas separation can be achieved. If it can’t be landed below the perforations, separators and special pumps may be employed. Results may or may not be satisfactory depending on many factors.
Pumps are usually employed when the bottom-hole pressure is low in the well or the gas/liquid ratio is not high enough for flowing, plunger lift, or other non pumping methods.
Gas-lift is a method whereby additional gas is injected down the tubing/casing annulus, or in some cases down coiled tubing. The gas is injected (hopefully) at or near the bottom of the well. Unloading valves above the operating gas-lift valve may be necessary to permit the well to inject at the desired depth with minimum compressor pressure to deliver the gas-lift gas.
For low pressure, low rate wells, the concept is to inject enough gas into the tubing to achieve critical velocity or rate so that the well will not liquid load. For larger liquid rates and pressures, more conventional gas-lift design principles may be applied.
For oil wells, gas-lift is considered to be a system that can not lower the bottom-hole pressure as much as with a pumping system. However, if critical rate is achieved without over injecting gas into a gas well, gas-lift may be as effective as pumping in achieving good gas production even in low pressure wells. Once a gas-lift system is in place, the installation is usually relatively trouble free. The compressor and gas-lift distribution systems are the most expensive parts of the system.
Unlike pumping and other forms of artificial lift, gas-lift uses gas for its operation so it is not hampered by gas interference as pumping systems are. Also, gas-lift systems are not affected by modest amounts of sand production.
Continuous gas-lift is applied to wells making low liquid rates. There are intermittent gas-lift methods and other approaches such as chamber lift, perhaps working with a plunger, which may also be designed for low liquid rates and low well pressures.
Foam is used with best results in gas wells making only water. It can handle deep wells and wells with moderate liquid rates. Chemical companies are making progress on developing foam or other chemical methods for wells that produce condensate.
From the discussion of critical rate, an intermediate equation for critical velocity was shown as:
υ 
1.92
σ
1
4

ρ
L
 ρ g

1
4
ρ g
1
2
This equation is a function of surface tension and liquid density. Surfactants will lower the values of both parameters, and as such will lower the required gas rate so that a lower gas rate can still be above critical rate.
Surfactants can be introduced into the well using three methods:

1. Soap sticks dropped down the tubing.
2. Surfactants dropped or pumped down the casing/tubing annulus (no packer).
3. Lubricate a capillary string (1/4” stainless steel tubing) through the wellhead down the tubing to the perforations.
Although soap sticks may be the most common method, the capillary string insures chemicals get to the desired depth in the well.
In some cases, it is possible to separate produced water down hole and inject it below a packer, below the gas zone, and into an underlying disposal zone, if all factors are in place.
Some beam and ESP systems have been developed to do this job.
Perflift TM (Schlumberger) is a method for installing a production string below a packer so gaslift can occur below the packer and through a long perforated zone. The goal is to reduce the pressure across even deep set perforations.
The CVR TM (Weatherford) system uses a large dead string in the perforated interval with assistance from surfactant injection to get flow to carry liquids from deep perforated intervals.
Plunger lift can be incorporated into the system.
A survey of Gas Production Operators was conducted at the 2006 Gas Well Deliquification
Workshop held in Denver, Colorado on Feb. 27- Mar. 1, 2006. Operators were asked a series of questions about their gas well deliquification practices. One that is pertinent here concerned the types of artificial lift systems they use.
Of 89 respondents, 78 (88%) said that they use plungers on some wells. The other responses can be seen in the table. Many Operators use more than one type or artificial lift. This makes sense since different wells have different needs.
Artificial Lift Systems Used
Total No. Returned Forms
Plunger Lift
# %
89 100%
78 88%
Batch Chemical
Continuous Chemical
38
45
43%
51%
ESP
PCP
Sucker Rod Pump
Continuous Gas-Lift
Intermittent Gas-Lift
Capillary Tube
Stop Cock (Intermit)
Heater
7
6
1
11
42
15
36
27
8%
12%
47%
17%
7%
40%
30%
1%
Other 14 16%
It is worth noting that while many Operators use what may be termed as “conventional” methods of artificial lift for gas well deliquification; there is a large continuing focus on devel-

opment and testing of new techniques in virtually all areas of artificial lift technology. People are continuing to look for more economical artificial lift systems to install and operate that will result in high gas production rates and higher ultimate recoveries.
Automation and optimization of artificial lift systems that are used for gas well deliquification is becoming a major concern. Several companies are developing or enhancing their artificial lift systems to monitor, control, and optimize plunger lift, pumping systems, gas-lift systems, etc. This is a large field by itself and may become the subject of a future article or series of articles.
Liquid loading is a condition that will eventually occur in nearly all gas wells. The industry is responding by optimum application of older artificial methods and development of new techniques. The reward of higher gas production rates and larger ultimate gas recovery volumes is very real.
1. Turner, R. G.; Hubbard, M. G. and Dukler, A. E. “Analysis and Prediction of Minimum Flow
Rate for the Continuous Removal of Liquids from Gas Wells”, J. Petroleum Technology, Nov.
1969. pp.1475-1482.
2. Coleman, S. B, Clay, H. B., McCurdy, D. G and Norris, H. L. III, “A New Look at Predicting
GasWell Load Up”, Journal of Petroleum Technology, March, 1991, pp. 329-333
3. Gas Well Deliquification , by J. Lea, H. Nickens, and M. Wells, 1st Edition, Gulf Professional
Publishing- Elsevier, 2003.
4. Gas Well Deliquification , by J. Lea, H. Nickens, and M. Wells, 2nd Edition, Gulf Professional
Publishing- Elsevier, 2008.