Deliquification - George E King Petroleum Engineering Oil and Gas

Transcription

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
What Technology
Will Drive Deliquification?
Technology
Cost, price?
Life Cycle of a Gas Well
May Add Energy
to System
What’s New?
2
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.
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.
4
Example: Oklahoma Gas Wells
Gas Production Per Well mcf/d
Oklahoma Gas Production Per Well
Average Flow Per Well
250
200
150
100
32,672 producing gas wells in 2001
50
0
1992
1994
1996
1998
2000
5
Tubing Performance - Vertical
Oil Well
P
gas, oil
and water
oil, water
and gas
oil
Gas Well
Water vapor
condenses as
gas rises and
expands.
P
gas and
liquid
DT
Water must be
removed to
allow the well to
flow.
Water that
builds up holds
a backpressure
on the
formation.
gas
6
Turner Unloading Rate, Water
For pressures > 1000 psi
3000
4.5" (3.958" ID)
3.5" (2.992" ID)
Gas Rate (mscf/d)
2500
2.875" (2.441" ID)
2.375" (1.995" ID)
2000
2.0675" (1.751" ID)
1500
1000
500
0
0
100
200
300
400
500
Flowing Pressure, psi
Source – J. Lea, Texas Tech, Turner Correlations.
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.
8
Small Gas Well Example – Lift
Progression – 2-3/8” Tubing
Gas Flow Rate, MSCFD
Flow and Lift - 2-3/8" Tubing
2000
1800
1600
1400
1200
1000
800
600
400
200
0
Flow to here
then plunger
then ?
0
20
40
60
Percent of Well Life
80
100
9
Source
Bryan
Dotson
We’ll have to put energy into
the well:
Pump Power
(assum es 50% Efficiency and 200 psid friction drop)
9
1000' depth
8
5000' depth
Pump HP
7
10000' depth
6
5
4
3
Low Pow er is 1-10 HP.
Micro Pow er is less than
2 HP.
2
1
0
1
5
10
25
50
100
150
200
BPD of Water
10
How Much Can We Pay?
$300,000
If plungers get us to 50
MSCFD, we can’t afford
too much..
$250,000
$200,000
$150,000
$140,000
$100,000
$50,000
$280,000
$70,000
$15,000
$0
10
50
100
200
Incremental M SCFD
11
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.
12
Monobore
High
Packer
Liner and
& Gap
Long
Monobore
& Tail Pipe
Small Tail
Pipe
V6
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.
Tapered
String and
Restrictions
V5
V4
V2
V3
V3
V1+
V3
V2
V2
V2
V1
V1
V1
V1
13
Gas Bubble Growth With Rise
In A Water Column
292
cm3
2 cm3
1 cm3
surface
14.7 psi (1 bar)
5000 ft
(1524m)
2150 psi (146 bar)
10000 ft
(3049m)
4300 psi (292 bar)
Gas column is different – gas is low density at the top of a
column and higher density
at bottom – so although rate is14
constant, velocity is not.
52887040.ppt
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.
15
Where is Critical Rate Calculated?
Surface or Bottom Hole?
Pres:
Temp:
Tbg:
Rate:
400#
60 deg F
1 ¼” CT
200 mscfd
Wellhead
Critical Rate:
180 mscfd
10,000’ 1 ¼” CT
Pres:
Temp:
900#
200 deg F
Bottom of Tubing
Critical Rate:
220 mscfd
10,500’ 3 ½” Csg to Perfs
Pres:
Temp:
1100#
Casing
200 deg
F
Critical Rate:
1500 mscfd
16
Water Content of Wet Gas
Pressure
14.7
STB/MMscf
10000.00
100
200
1000.00
500
1000
100.00
2000
3000
10.00
4000
5000
1.00
0.10
0.01
50
100
150
200
250
300
350
Temperature (deg F)
How much potential water condensation are we facing?
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.
18
Diagnostics: The production history of a well starting to load
up. There are usually many causes that lead to load-up.
19
Gas Rate (MCF/D)
10/31/2000
10/24/2000
10/17/2000
10/10/2000
10/3/2000
9/26/2000
9/19/2000
9/12/2000
Champlin 242-C3
9/5/2000
8/29/2000
8/22/2000
8/15/2000
8/8/2000
8/1/2000
7/25/2000
7/18/2000
7/11/2000
7/4/2000
6/27/2000
6/20/2000
6/13/2000
6/6/2000
5/30/2000
5/23/2000
5/16/2000
5/9/2000
5/2/2000
4/25/2000
Typical Wamsutter New Well Decline
3500
3-1/2” Production Casing
3000
2500
2000
1500
1000
500
0
Line Pressure (PSI)
20
Note pressures
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.
21
An increase in
the differential
between casing
and tubing
pressure over
time indicates
loading.
No packer
example.
Csg-tbg
pressure
Time
22
Gradient survey to locate static liquid level.
23
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?
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
25
What causes
the sharp
initial decline
when the
well is
brought on?
Q
What causes the short-lived increases
in rate when a well is started up after a
brief shut-in?
Can it be used for
advantage?
Cumulative Production
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
27
Shutting in a Well at Surface Doesn’t Mean the Flow Stops Downhole!
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
shale
Fractured, high perm
shale
10 md
10 md
1 md
1 md
shale
shale
10 md
10 md
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.
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.
30
Well With A Plunger Installation
Installed Plunger
31
Effective CT Velocity String – Champlin 149-B2
7” Casing
2-3/8” Tubing
1-1/4” CT
1200
CT Installed
1000
Total Cost: $20,121
MCFD
Tubing PSI
Casing PSI
Line PSI
Projection
800
600

400
Paid out in 3 months
200
11
/1
/1
99
11
6
/1
5/
11 199
6
/2
9/
19
12
96
/1
3/
12 199
6
/2
7/
19
9
1/
10 6
/1
1/ 997
24
/1
99
7
2/
7/
19
97
2/
21
/1
99
7
3/
7/
19
97
3/
21
/1
99
7
4/
4/
19
97
4/
18
/1
99
7
5/
2/
19
97
5/
16
/1
99
5/
30 7
/1
6/ 997
13
/1
99
6/
27 7
/1
7/ 997
11
/1
99
7/
25 7
/1
99
7
8/
8/
19
97
8/
22
/1
99
7
9/
5/
19
97
9/
19
/1
99
10
7
/3
/1
9
10
/1 97
7/
19
10
97
/3
1/
19
97
0
Average rate for 90 days prior to installation: 246 mcfd
Average for last 30 days: 327 mcfd
32
MCFD
Average rate for 90 days prior to installation: 911 mcfd
Line PSI
projection
Average rate for last 30 days: 539 mcfd
12/22/2000
12/8/2000
11/24/2000
200
11/10/2000
10/27/2000
1200
1000
-20
800
-40
600
-60
400
-80

0
MMCF
1-1/4” CT
10/13/2000
9/29/2000
9/15/2000
9/1/2000
8/18/2000
8/4/2000
7/21/2000
7/7/2000
6/23/2000
6/9/2000
2-3/8” Tubing
5/26/2000
5/12/2000
4/28/2000
4/14/2000
3/31/2000
3/17/2000
3/3/2000
2/18/2000
5-1/2” Casing
2/4/2000
1/21/2000
1/7/2000
12/24/1999
12/10/1999
11/26/1999
11/12/1999
10/29/1999
10/15/1999
10/1/1999
MCFD
Ineffective CT Velocity String – Champlin 222-C2
Gross Cost: $19905
0
CT Installed
-100
-120
cumwedge
33
3/1
/0
0
3/8
/0
3/1 0
5/
0
3/2 0
2/
0
3/2 0
9/
00
4/5
/0
4/1 0
2/
0
4/1 0
9/
0
4/2 0
6/
00
5/3
/0
5/1 0
0/
0
5/1 0
7/
0
5/2 0
4/
0
5/3 0
1/
00
6/7
/0
6/1 0
4/
0
6/2 0
1/
0
6/2 0
8/
00
7/5
/0
7/1 0
2/
0
7/1 0
9/
0
7/2 0
6/
00
8/2
/0
0
8/9
/0
8/1 0
6/
0
8/2 0
3/
0
8/3 0
0/
00
9/6
/0
9/1 0
3/
0
9/2 0
0/
0
9/2 0
7/
0
10 0
/4/
10 00
/11
10 /00
/18
10 /00
/25
/0
11 0
/1/
00
Gas Rate (MCF/D)
Soap Injection to Reduce Fluid Column Hydrostatic
1800
CT Installed
CG Road 25-4
3-1/2” Casing
1-1/4” CT
Soap Injection
1600
1400
1200
1000
800
600
400
200
Venting to unload wellbore
0
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 www.GEKEngineering.com
wells may still produce but are 35
very erratic.
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!
36
Pressure
Effects of
Liquid
Loading
37
Heating Gas – Downhole View During Gas Flow
38
Jason Piggot, SPE 2002
39
40
41
Unstable Gas Well Flow Behavior, Followed by Loading
1,000
900
800
Loading
600
500
400
300
200
100
99
A-
99
A-
8
-9
D
98
A-
98
A-
D
-9
7
97
A-
97
A-
6
-9
D
96
A-
96
A-
5
-9
D
95
A-
95
A-
4
-9
D
94
0
A-
MCF/Day
700
42
Heating Gas – Effects on Production
0
20
40
60
80
100
120
140
0
1000
2000
Depth
3000
4000
5000
6000
7000
Pressure, psig
Before Heating
After Heating
43
Pressure Effects of Liquid Loading
Pressure, psia
60
70
80
90
100
110
120
130
0
1000
Liquid Loading
Results in 30 PSI
Back-Pressure
2000
Depth
3000
4000
5000
6000
7000
Flowing
Shut-in
44
700
Shutdow n for 3 Phase
Pow er Installation
Line Restrictions Removed at Surface
Current System Operational
Cable Operational
3 Phase Pow er Installed
600
500
Testing
Generator
Test
MCFD
400
300
200
100
Compressor Changed
Screw Compressor to 3 Stage
0
ay
M
00
00
nJu
0
l-0
Ju
00
gAu
00
pSe
O
00
ct-
00
vNo
00
cDe
01
nJa
1
01
-0
bar
Fe
M
1
r-0
Ap
ay
M
01
01
nJu
1
l-0
Ju
01
gAu
01
pSe
O
01
ct-
01
vNo
01
cDe
02
nJa
2
02
-0
bar
Fe
M
45
600
Tubing & Casing Flow
Compressor On
Cable On
Casing Flow Only
Cable On
Compressor On
500
Compressor On
Cable On
Tubing Flow Only
Compressor On
Cable On
400
300
Compressor On
Cable Off
200
100
Compressor Dow n
Compressor Dow n
Temperature, Deg. Fahrenheit
Pressure, psig
411
401
391
381
371
361
351
341
331
321
311
301
291
281
271
261
251
241
231
221
211
201
191
181
171
161
151
141
131
121
111
101
91
81
71
61
51
41
31
21
11
1
0
Rate, Mcf/Day
46
Heating Gas – Effects on Temperature Gradient
0
50
100
150
200
250
300
0
1,000
2,000
Depth, ft.
3,000
4,000
5,000
6,000
7,000
Temperature, F
After Heating
Before Heating
47
48
49
Support Slides
• Lift Methods
• Deviated Wells
• Critical Flow Calculations
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).
51
Method
Natural
Flow
Description
Flow of liquids up the
tubing propelled by
expanding gas bubbles.
Pros
Cheapest and
most steady
state flow
Cons
May not be
optimum flow.
Higher BHFP
than with lift.
Contin Adding gas to the produced Cheap. Most
uous
fluid to assist upward flow
widely used lift
Gas Lift of liquids. 18% efficient.
offshore.
Still has high
BHFP. Req.
optimization.
ESP or
HSP
Costly. Short
life. Probs. w/
gas, solids, and
heat.
Electric submersible motor
driven pump. 38% efficient.
Or hydraulic driven pump
(req. power fluid path).
Can move v.
large volumes of
liquids.
52
Method
Description
Pros
Cons
Hydraul Hydraulic power fluid
ic
driven pump. 40% efficient.
pump
Works deeper
than beam lift.
Less profile.
Req. power
fluid string and
larger wellbore.
Beam
Lift
V. Common unit,
well understood,
Must separate
gas, limited on
depth and
pump rate.
Varies with
techniques.
New - sharp
learning curve.
Walking beam and rod
string operating a
downhole pump. Efficiency
just over 50%.
Special Diaphram or other style of
ty
pump.
pumps
53
Method
Description
Pros
Cons
Intermit Uses gas injected usually at
tent
one point to kick well off or
Gas Lift 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
Cheap, works on
pushed by gas below to
low pressure
mover a quantity ofwww.GEKEngineering.com
liquids wells, control by
above the plunger.
simple methods
Limited volume
of water moved,
54
cycles
backpressure.
Method
Pros
Cons
Soap
Forms a foam with gas
Injection from formation and water
to be lifted.
Does not require
downhole mods.
Costly in vol.
Low water flow.
Condensate is a
problem.
Compres Mechanical compressor
sion
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
Description
Inserts smaller string in
Relatively low
existing tbg to reduce flow cost and easy
area and boost velocity
Higher friction,
corrosion and
less access.
55
Method
Description
Pros
Cons
Cycling / Flow well until loading
Cheap. Can be
Intermitt starts, then shut in until
effective if optm.
er
pressures build, then flow. 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
Cheap, simple,
increase velocity and
no equipment
decrease BHFP. www.GEKEngineering.com
needed.
Not
environmentally
friendly. 56
Very Generalized Operating Ranges for Some Lift
Systems.
Note that some lift systems are depth limited and some are
volume limited. Almostwww.GEKEngineering.com
all are limited to some extent by the
57
diameter of the wellbore.
Deviated Wells
• About 30% of US produced gas comes
from offshore.
• Most offshore wells are deviated – Flow is
very different in deviated wells!
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.
59
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.
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.
60
Oilfield Review
61
Note the flow
velocity
difference
between the
top and
bottom of the
pipe.
Oilfield Review
62

Deliquification - George E King Petroleum Engineering Oil and Gas

Transcription

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