Low Pressure Gas Well
Deliverability Issues: Common
Loading Causes, Diagnostics
and Effective Deliquification
Practices
George E. King
Brownfields: Optimizing Mature Assets Conference,
September 19-20, 2005, Denver, Colorado.
www.GEKEngineering.com 1
May Add Energy to System
What’s New?
Technology - Cost, price?
What Technology Will Drive Deliquification?
Life Cycle of a Gas Well
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US Mature Well Base (2001)
• 880,000 producing or temporarily
abandoned wells
• 320,000 gas wells (many at 5 to 15 mcf/d)
• Vast majority of these wells are low
pressure and low rate.
www.GEKEngineering.com 3
Gas Wells: Two Facts
• Potential: Very long life in some cases –
30 to over 70 years and large recovery for
every extra 10 psi drawdown.
• Challenge: Liquid loading from condensed
or connate fluids will kill or sharply reduce
the production.
www.GEKEngineering.com 4
Example: Oklahoma Gas Wells
Oklahoma Gas Production Per Well
0
50
100
150
200
250
1992 1994 1996 1998 2000Gas P
rod
ucti
on
Per
Well
mcf/
d
32,672 producing gas wells in 2001
Average Flow Per Well
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Tubing Performance - Vertical P P
gas and
liquid
gas
Gas Well Oil Well
oil, water
and gas
oil
gas, oil
and water Water vapor
condenses as
gas rises and
expands.
Water must be
removed to
allow the well to
flow.
Water that
builds up holds
a backpressure
on the
formation.
DT
www.GEKEngineering.com 6
Turner Unloading Rate, Water
0
500
1000
1500
2000
2500
3000
0 100 200 300 400 500
Flowing Pressure, psi
Ga
s R
ate
(m
sc
f/d
)
4.5" (3.958" ID)
3.5" (2.992" ID)
2.875" (2.441" ID)
2.375" (1.995" ID)
2.0675" (1.751" ID)
Source – J. Lea, Texas Tech, Turner Correlations.
For pressures > 1000 psi
www.GEKEngineering.com 7
Minimum Critical Velocities
• Turner and Coleman Equations
• Estimate minimum gas flow velocity
needed to lift water droplets out of well.
• If flow velocity below critical, then water
droplets fall / build up in bottom of well.
• The well may or may not cease to flow
but production will be decreased.
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Small Gas Well Example – Lift
Progression – 2-3/8” Tubing
Flow and Lift - 2-3/8" Tubing
0
200
400
600
800
1000
1200
1400
1600
1800
2000
0 20 40 60 80 100
Percent of Well Life
Ga
s F
low
Ra
te, M
SC
FD
Flow to here
then plunger
then ?
Source -
Bryan
Dotson
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Pump Power (assumes 50% Efficiency and 200 psid friction drop)
0
1
2
3
4
5
6
7
8
9
1 5 10 25 50 100 150 200
BPD of Water
Pu
mp
HP
1000' depth
5000' depth
10000' depth
Low Pow er is 1-10 HP.
Micro Pow er is less than
2 HP.
We’ll have to put energy into
the well:
www.GEKEngineering.com 10
How Much Can We Pay?
1050
100200
$15,000
$70,000
$140,000
$280,000
$0
$50,000
$100,000
$150,000
$200,000
$250,000
$300,000
Incremental MSCFD
If plungers get us to 50 MSCFD, we can’t afford
too much..
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System Requirements
• Low initial cost.
• Reasonable life: 3-5 years; more is better.
• Low cost energy.
• Handle gas gracefully.
• Automatic pump-off control.
• 180F to 280F, to 12000 feet.
• Handle solids and paraffin well.
• Resistant to CO2 and H2S corrosion.
• Works in highly deviated wells.
• Acid-resistant.
• Resistant to scale formation.
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Monobore
High
Packer
Liner and
& Gap
Long
Monobore
& Tail Pipe
Small Tail
Pipe
Tapered
String and
Restrictions
V1
V2
V1
V2
V3
V1
V2
V3
V1
V2
V3
V4
V5
V6
V1+
The design
of the well
bore can
alter the
velocity.
Where is
critical rate
calculated?
Multiple
velocity
calculations
are needed
with gas in
compressed
state.
www.GEKEngineering.com 13
surface 14.7 psi (1 bar)
5000 ft 2150 psi (146 bar)
(1524m)
10000 ft 4300 psi (292 bar)
(3049m)
292 cm3
2 cm3
1 cm3
52887040.ppt
Gas Bubble Growth With Rise In A Water Column
Gas column is different – gas is low density at the top of a
column and higher density at bottom – so although rate is
constant, velocity is not. www.GEKEngineering.com 14
Liquids in Gas Wells
• Gas phase – condensing to a liquid
– Water – several bbls/mmcf, unusually fresh
– Condensate – can be much higher volume
• Connate Water
– Usually saltier than condensing water
– Often stays in bottom of the well.
www.GEKEngineering.com 15
Where is Critical Rate Calculated?
Surface or Bottom Hole? Pres: 400#
Temp: 60 deg F
Tbg: 1 ¼” CT
Rate: 200 mscfd
10,000’ 1 ¼” CT
Pres: 900#
Temp: 200 deg F
Wellhead
Critical Rate: 180 mscfd
Bottom of Tubing
Critical Rate: 220 mscfd
Casing
Critical Rate: 1500 mscfd
Pres: 1100#
Temp: 200 deg F
10,500’ 3 ½” Csg to Perfs
www.GEKEngineering.com 16
Water Content of Wet Gas
0.01
0.10
1.00
10.00
100.00
1000.00
10000.00
50 100 150 200 250 300 350
Temperature (deg F)
ST
B/M
Mscf
14.7
100
200
500
1000
2000
3000
4000
5000
Pressure
How much potential water condensation are we facing? www.GEKEngineering.com 17
Condensation Drivers
• Loss of temperature
– Gas condenses to liquid phase
• Loss of Rate
– Slower velocity =>
• Poorer lift potential.
• Longer transit times, more heat loss, more
condensation opportunity.
– Less flowing mass => less total heat to loose
before water starts to condense.
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Diagnostics: The production history of a well starting to load
up. There are usually many causes that lead to load-up.
www.GEKEngineering.com 19
0
500
1000
1500
2000
2500
3000
35004
/25
/20
00
5/2
/20
00
5/9
/20
00
5/1
6/2
00
0
5/2
3/2
00
0
5/3
0/2
00
0
6/6
/20
00
6/1
3/2
00
0
6/2
0/2
00
0
6/2
7/2
00
0
7/4
/20
00
7/1
1/2
00
0
7/1
8/2
00
0
7/2
5/2
00
0
8/1
/20
00
8/8
/20
00
8/1
5/2
00
0
8/2
2/2
00
0
8/2
9/2
00
0
9/5
/20
00
9/1
2/2
00
0
9/1
9/2
00
0
9/2
6/2
00
0
10
/3/2
00
0
10
/10
/20
00
10
/17
/20
00
10
/24
/20
00
10
/31
/20
00
Gas Rate (MCF/D) Line Pressure (PSI)
Typical Wamsutter New Well Decline
Champlin 242-C3 3-1/2” Production Casing
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Liquid
holdup
from
declining
velocity
The liquid
holdup
applies a
backpress
ure to the
bottom
hole.
Rate is
decreased
Enough
liquid
finally
drops
down the
well to
reduce or
balance
formation
pressure.
Flow is
decreased
or the well
is dead.
Note pressures
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An increase in
the differential
between casing
and tubing
pressure over
time indicates
loading.
No packer
example.
Time
Csg-tbg
pressure
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Gradient survey to locate static liquid level.
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Lift Selection Considerations
• Size of the prize?
• Cost of water prod?
• How much water?
• Source?
– Water control?
• Condensation cause?
• Condense location?
• Well limits?
• Safety valve?
• Power?
• Computer control?
• Well W/O costs?
• Well W/O risks?
www.GEKEngineering.com 24
Lift and Deliquification
• Natural Flow
• Intermitter
• Rocking
• Equalizing
• Venting
• Soaping
• Velocity String
• Compression
• Gas Lift
• Beam Lift
• Plunger
• ESP and HSP
• PCP
• Diaphragm Pump
• Jet Pump
• Eductor
www.GEKEngineering.com 25
What causes the short-lived increases
in rate when a well is started up after a
brief shut-in?
Q
Cumulative Production
Can it be used for
advantage?
What causes
the sharp
initial decline
when the
well is
brought on?
www.GEKEngineering.com 26
Why the increase after a shut-in?
1. Recharging of the near wellbore from the
formation away from the wellbore.
2. Cross flow from low permeability, higher
pressure zones to high permeability,
partly depleted zones (also recharging).
– High perm streaks
– Natural fractures
– Stimulated fractures
www.GEKEngineering.com 27
Most formations are
layered and often have
distinctly different
permeabilities in a
package of pay.
These layers flow as
individual units,
emptying the higher
perm units first before
the lower perm
reservoirs begin to flow.
When a well is shut in,
higher remaining
pressures in the low
perm layers cause flow
into the high perm, more
depleted streaks.
Natural cross flow!
fractured Fractured, high perm
shale shale
shale shale
10 md 10 md
1 md 1 md
10 md 10 md
Shutting in a Well at Surface Doesn’t Mean the Flow Stops Downhole!
www.GEKEngineering.com 28
Using Cross Flow
• Repressuring the higher permeability streaks
during a shut-in can lend a sharp, short lived
increase to flow and can help unload a well
without outside equipment or services.
• To use it effectively, the behavior of the well
such as how quickly it recharges, how quickly it
blows down and what happens to the water
during a shut-in must be understood.
www.GEKEngineering.com 29
Lift and Unloading Options
• At least 15 options of full time and part
time lift.
• The well design, conditions and
economics dictate the optimum method –
and remember – both can change with
decline.
• Another very important contributor is the
operator.
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Well With A Plunger Installation
Installed Plunger
www.GEKEngineering.com 31
0
200
400
600
800
1000
1200
11/1
/199
6
11/1
5/199
6
11/2
9/199
6
12/1
3/199
6
12/2
7/199
6
1/10
/199
7
1/24
/199
7
2/7/
1997
2/21
/199
7
3/7/
1997
3/21
/199
7
4/4/
1997
4/18
/199
7
5/2/
1997
5/16
/199
7
5/30
/199
7
6/13
/199
7
6/27
/199
7
7/11
/199
7
7/25
/199
7
8/8/
1997
8/22
/199
7
9/5/
1997
9/19
/199
7
10/3
/199
7
10/1
7/199
7
10/3
1/199
7
MCFD
Tubing PSI
Casing PSI
Line PSI
Projection
Total Cost: $20,121
Average rate for 90 days prior to installation: 246 mcfd Average for last 30 days: 327 mcfd
Paid out in 3 months
Effective CT Velocity String – Champlin 149-B2
CT Installed
7” Casing 2-3/8” Tubing 1-1/4” CT
www.GEKEngineering.com 32
0
200
400
600
800
1000
1200
10
/1/1
99
9
10
/15
/19
99
10
/29
/19
99
11
/12
/19
99
11
/26
/19
99
12
/10
/19
99
12
/24
/19
99
1/7
/20
00
1/2
1/2
00
0
2/4
/20
00
2/1
8/2
00
0
3/3
/20
00
3/1
7/2
00
0
3/3
1/2
00
0
4/1
4/2
00
0
4/2
8/2
00
0
5/1
2/2
00
0
5/2
6/2
00
0
6/9
/20
00
6/2
3/2
00
0
7/7
/20
00
7/2
1/2
00
0
8/4
/20
00
8/1
8/2
00
0
9/1
/20
00
9/1
5/2
00
0
9/2
9/2
00
0
10
/13
/20
00
10
/27
/20
00
11
/10
/20
00
11
/24
/20
00
12
/8/2
00
0
12
/22
/20
00
MC
FD
-120
-100
-80
-60
-40
-20
0
MM
CF
MCFD Line PSI projection cumwedge
Gross Cost: $19905
Average rate for 90 days prior to installation: 911 mcfd Average rate for last 30 days: 539 mcfd
Ineffective CT Velocity String – Champlin 222-C2
5-1/2” Casing 2-3/8” Tubing 1-1/4” CT
CT Installed
www.GEKEngineering.com 33
0
200
400
600
800
1000
1200
1400
1600
1800
3/1/00
3/8/00
3/15
/00
3/22
/00
3/29
/00
4/5/00
4/12
/00
4/19
/00
4/26
/00
5/3/00
5/10
/00
5/17
/00
5/24
/00
5/31
/00
6/7/00
6/14
/00
6/21
/00
6/28
/00
7/5/00
7/12
/00
7/19
/00
7/26
/00
8/2/00
8/9/00
8/16
/00
8/23
/00
8/30
/00
9/6/00
9/13
/00
9/20
/00
9/27
/00
10/4/00
10/11/00
10/18/00
10/25/00
11/1/00
Gas R
ate
(M
CF
/D)
Soap Injection to Reduce Fluid Column Hydrostatic
Soap Injection
Venting to unload wellbore
CT Installed
CG Road 25-4 3-1/2” Casing 1-1/4” CT www.GEKEngineering.com 34
Conclusions
• Small increases in pressure drop can
make large gains in production.
– Every ft of liquid in a well holds nearly ½ psi in
backpressure on the formation.
– Water invading the pores of the rock during a
shut-in can be held on the formation and gas
cannot displace it.
– Water refluxing in a gas well is the largest
single source of corrosion.
– Liquid loaded wells may still produce but are
very erratic. www.GEKEngineering.com 35
Conclusions
• Tubng size is a legitimate and low cost
choice ONLY if GLR will allow the well to
be placed in mist flow.
• Lift consideration should include the limits
and well as the advantages.
• If Turner or Coleman correlations do not
work in your applications, develop your
own – Really, it’s OK!
www.GEKEngineering.com 36
Pressure
Effects of
Liquid
Loading
www.GEKEngineering.com 37
Jason Piggot, SPE 2002
Heating Gas – Downhole View During Gas Flow
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Jason Piggot, SPE 2002
Heating Gas – Downhole View During Gas Flow
www.GEKEngineering.com 39
Jason Piggot, SPE 2002
Heating Gas – Downhole View During Gas Flow
www.GEKEngineering.com 40
Jason Piggot, SPE 2002
Heating Gas – Downhole View During Gas Flow
www.GEKEngineering.com 41
0
100
200
300
400
500
600
700
800
900
1,000
A-9
4
D-9
4A-9
5A-9
5
D-9
5A-9
6A-9
6
D-9
6A-9
7A-9
7
D-9
7A-9
8A-9
8
D-9
8A-9
9A-9
9
MC
F/D
ay
Loading
Jason Piggot, SPE 2002
Unstable Gas Well Flow Behavior, Followed by Loading
www.GEKEngineering.com 42
Jason Piggot, SPE 2002
Heating Gas – Effects on Production
7000
6000
5000
4000
3000
2000
1000
0
0 20 40 60 80 100 120 140
Pressure, psig
Depth
Before Heating After Heatingwww.GEKEngineering.com 43
7000
6000
5000
4000
3000
2000
1000
0
60 70 80 90 100 110 120 130
Pressure, psia
Depth
Flowing Shut-in
Liquid Loading
Results in 30 PSI
Back-Pressure
Jason Piggot, SPE 2002
Pressure Effects of Liquid Loading
www.GEKEngineering.com 44
Jason Piggot, SPE 2002
Heating Gas – Effects on Production
0
100
200
300
400
500
600
700
May
-00
Jun-
00
Jul-0
0
Aug-0
0
Sep-0
0
Oct-0
0
Nov
-00
Dec
-00
Jan-
01
Feb-0
1
Mar
-01
Apr-0
1
May
-01
Jun-
01
Jul-0
1
Aug-0
1
Sep-0
1
Oct-0
1
Nov
-01
Dec
-01
Jan-
02
Feb-0
2
Mar
-02
MC
FD
Generator
Test
Shutdow n for 3 Phase
Pow er Installation
Cable Operational
3 Phase Pow er Installed
Line Restrictions Removed at Surface
Compressor Changed
Screw Compressor to 3 Stage
Current System Operational
Testing
www.GEKEngineering.com 45
Jason Piggot, SPE 2002
Heating Gas – Effects on Production
0
100
200
300
400
500
600
1
11
21
31
41
51
61
71
81
91
101
111
121
131
141
151
161
171
181
191
201
211
221
231
241
251
261
271
281
291
301
311
321
331
341
351
361
371
381
391
401
411
Temperature, Deg. Fahrenheit Pressure, psig Rate, Mcf/Day
Tubing & Casing Flow
Compressor On
Cable On Casing Flow Only
Cable On
Compressor On
Compressor Dow n
Tubing Flow Only
Compressor On
Cable On
Compressor Dow n
Tubing & Casing Flow
Compressor On
Cable On
Tubing & Casing Flow
Compressor On
Cable Off
www.GEKEngineering.com 46
Jason Piggot, SPE 2002
Heating Gas – Effects on Temperature Gradient
7,000
6,000
5,000
4,000
3,000
2,000
1,000
0
0 50 100 150 200 250 300
Temperature, F
De
pth
, ft.
After Heating Before Heating
www.GEKEngineering.com 47
Jason Piggot, SPE 2002
Heating Gas – Downhole View During Gas Flow
www.GEKEngineering.com 48
Jason Piggot, SPE 2002
Heating Gas – Downhole View During Gas Flow
www.GEKEngineering.com 49
Support Slides
• Lift Methods
• Deviated Wells
• Critical Flow Calculations
www.GEKEngineering.com 50
Lift Methods and Unloading
Options
• Most mechanical methods are build for oil
wells – that’s grossly over designed for
gas wells and much too expensive.
• A “dry” gas well may produce on 4 to 16
ounces per minute (100 to 500 cc/min).
www.GEKEngineering.com 51
Method Description Pros Cons
Natural
Flow
Flow of liquids up the
tubing propelled by
expanding gas bubbles.
Cheapest and
most steady
state flow
May not be
optimum flow.
Higher BHFP
than with lift.
Contin
uous
Gas Lift
Adding gas to the produced
fluid to assist upward flow
of liquids. 18% efficient.
Cheap. Most
widely used lift
offshore.
Still has high
BHFP. Req.
optimization.
ESP or
HSP
Electric submersible motor
driven pump. 38% efficient.
Or hydraulic driven pump
(req. power fluid path).
Can move v.
large volumes of
liquids.
Costly. Short
life. Probs. w/
gas, solids, and
heat.
Lift and Unloading Options
www.GEKEngineering.com 52
Method Description Pros Cons
Hydraul
ic
pump
Hydraulic power fluid
driven pump. 40% efficient.
Works deeper
than beam lift.
Less profile.
Req. power
fluid string and
larger wellbore.
Beam
Lift
Walking beam and rod
string operating a
downhole pump. Efficiency
just over 50%.
V. Common unit,
well understood,
Must separate
gas, limited on
depth and
pump rate.
Special
ty
pumps
Diaphram or other style of
pump.
Varies with
techniques.
New - sharp
learning curve.
Lift and Unloading Options
www.GEKEngineering.com 53
Method Description Pros Cons
Intermit
tent
Gas Lift
Uses gas injected usually at
one point to kick well off or
unload the well followed by
natural flow. 12% efficient.
Cheap and
doesn’t use the
gas volume of
continuous GL.
Does little to
reduce FBHP
past initial
kickoff.
Jet
pump
Uses a power fluid through
a jet to lift all fluids
Can lift any GOR
fluid.
Req. power
fluid string.
Probs with
solids.
PCP Progressive cavity pump. Can tolerate v.
large volumes of
solids and ultra
high visc. fluids.
Low rate,
costly, high
power
requirements.
Plunger A free traveling plunger
pushed by gas below to
mover a quantity of liquids
above the plunger.
Cheap, works on
low pressure
wells, control by
simple methods
Limited volume
of water moved,
cycles
backpressure.
Lift and Unloading Options
www.GEKEngineering.com 54
Method Description Pros Cons
Soap
Injection
Forms a foam with gas
from formation and water
to be lifted.
Does not require
downhole mods.
Costly in vol.
Low water flow.
Condensate is a
problem.
Compres
sion
Mechanical compressor
scavenges gas from well,
reducing column wt and
increasing velocity.
Does not require
downhole mods.
Cost for
compressor
and operation.
Limited to low
liquid vols.
Velocity
Strings
Inserts smaller string in
existing tbg to reduce flow
area and boost velocity
Relatively low
cost and easy
Higher friction,
corrosion and
less access.
Lift and Unloading Options
www.GEKEngineering.com 55
Method Description Pros Cons
Cycling /
Intermitt
er
Flow well until loading
starts, then shut in until
pressures build, then flow.
Cheap. Can be
effective if optm.
No DH mods.
Req. sufficient
pressure and
automation (?)
Equalizi
ng
Shuts in after loading.
Building pressure pushes
gas into well liquids and
liquids into the formation.
Will work if
higher perm and
pressure. No
downhole mods.
Takes long
time. May
damage
formation.
Rocking Pressure up annulus with
supply gas and then blow
tubing pressure down.
Inexpensive and
usually
successful.
Req. high press
supply gas.
Well has no
packer.
Venting
Blow down the well to
increase velocity and
decrease BHFP.
Cheap, simple,
no equipment
needed.
Not
environmentally
friendly.
Lift and Unloading Options
www.GEKEngineering.com 56
Very Generalized Operating Ranges for Some Lift
Systems.
Note that some lift systems are depth limited and some are
volume limited. Almost all are limited to some extent by the
diameter of the wellbore. www.GEKEngineering.com 57
Deviated Wells
• About 30% of US produced gas comes
from offshore.
• Most offshore wells are deviated – Flow is
very different in deviated wells!
www.GEKEngineering.com 58
The liquid flow character can
change dramatically with depth
and deviation.
Severe liquid holdup by reflux
motion is common in the
Boycott Settling range of 30o to
60o.
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In deviated wells, liquid holdup,
sometimes seen as a reflux or
percolation in sections of the
tubing, can account for large
volumes of water and significant
backpressure on the formation.
Liquid Holdup –
Driven By Density
Segregation In a vertical
well, the
falling liquid
droplet may
be lifted if
the rising
gas more
than offsets
the fall of the
liquid.
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Oilfield Review
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Oilfield Review
Note the flow
velocity
difference
between the
top and
bottom of the
pipe.
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