Analysis of Gas Lift Transient Effects
Henry NickensAdam Ballard
BP - Houston
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Gas Lift Instability
• Steady-state methods for gas lift design and analysis do not capture the pressure/temperature transients that inevitably occur in an operating gas lifted well.
• Transient well response occurs during:
– Unloading the well
– Well shut-down
– Normal well operation (e.g., tubing/casing heading, multi-pointing)
– Well kick off or shut-down with CT
• This paper presents analysis of gas lift instability for two design cases:
1. To aid in selection of optimum tubing size (5.5 in vs 7 in)
2. To determine hydrate formation in CT gas lift after shut-down
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Gas Lift Instabiliy
• OLGA2000 version 4.01 was used to model the wells
– transient multi-phase flow simulator
– developed by Scandpower
• Two cases are studied:
1. New well design to determine
– optimum tubing size
– Effect of injection rate, orifice size and wellhead pressure
2. CT gas lift shut-down to determine time to hydrate formation
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Gas Lift Instability – Case 1
A new well is to be drilled. Steady-state analysis shows that gas lifting 7-inch tubing gives potentially much greater production than 5.5-inch tubing.
What is the expected stability of the well for the range of expected injection rates, production rates and water cuts?
The onset of instability (severe slugging) was calculated as a function of injection rate and water cut to define the expected operating window for instability.
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Well Characteristics – Case 1
• 5 ½“ or 7 “ ERD
• Production Fluid– 860 scf/stb GOR– 33 oil API– 0.663 gas SG– 20000 ppm water salinity
• Gas lift– gas injection valve at 16000 feet MD (0.8125” ID)– 1595 psia gas injection pressure– 0.7 gas SG
0
1000
2000
3000
4000
5000
6000
7000
8000
9000
10000
0 5000 10000 15000 20000
Horizontal Distance (feet)
TV
D (
feet
)
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OLGA Model – Case 1
• Model setup
– WELL module used for inflow
– constant P boundaries at tubing head and casing head
– choke controlled for constant gas rate
– gas lift orifice ID of 0.8125”
Well
PPPP
Annulus Tubing
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Comparison of OLGA with Steady- State Simulators Case 1
9500
9700
9900
10100
10300
10500
10700
10900
11100
0 1 2 3 4 5 6 7 8
Gas Injection Rate (mmscf/d)
Oil
Rate
(st
b/d
)
OLGAPROSPERPIPESIM
5.5" ERD Well0% Watercut1595 psia Injection 232 psia THP2538 psia Pres
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Sample Result – Case 1 – 5.5”
0
2000
4000
6000
8000
10000
12000
0 1 2 3 4 5 6 7 8 9
Gas Injection Rate (mmscf/d)
Oil
Ra
te (
stb
/d)
1595 psia Injection 232 psia THP2538 psia Pres
0% Watercut
40% Watercut
95% Watercut
OLGA - Solid LinesPROSPER - Dashed Lines
60% Watercut
80% Watercut
Transient FlowUnstable Flow – Onset of Slugging
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Sample Result – Case 1 – 7”
0
2000
4000
6000
8000
10000
12000
14000
16000
18000
20000
0 1 2 3 4 5 6 7 8 9
Gas Injection Rate (mmscf/d)
Oil
Ra
te (
stb
/d)
7" ERD Well1595 psia Injection
232 psia THP2538 psia Pres
0% Watercut
40% Watercut
OLGA - Solid LinesPROSPER - Dashed Lines
Flow
95% Watercut
80% Watercut
60% Watercut
Unstable Flow – Onset of Slugging
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Conclusions - Case 1 - Tubing ID
• The injection pressure did not have a significant impact on the stability of the flow.
• For both 7” and 5.5” tubing, flow is stable at watercuts below 80-90%
• The 5.5” tubing is more stable at higher watercuts.
• At 4 mmscf/d injection rate,
– the 5.5” tubing is stable up to 80% WC for both 1595 and 2030 psia injection pressures
– the 7” tubing is unstable at 80 % WC with 2030 psia injection pressure
• At 8 mmscf/d injection rate
– 5.5” tubing is stable for at all watercuts
– 7” tubing is unstable at 95 % watercut.
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Effect of Injection Rate on Stability
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2 MMscf/d Injection Rate - Case 1
0
5000
10000
15000
20000
25000
0 5000 10000 15000 20000 25000 30000 35000
Time (s)
Tota
l Liq
uid
Rate
(st
b/d
) OLGAPROSPER
5.5" ERD Well95% Watercut2 mmscf/d Gas Rate1595 psia Injection 232 psia THP2538 psia Pres
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4 MMscf/d Injection Rate - Case 1
0
1000
2000
3000
4000
5000
6000
7000
8000
9000
10000
0 5000 10000 15000 20000 25000 30000 35000 40000 45000
Time (s)
Tota
l Liq
uid
Rate
(st
b/d
)
OLGAPROSPER
5.5" ERD Well95% Watercut4 mmscf/d Gas Rate1595 psia Injection 232 psia THP2538 psia Pres
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8 MMscf/d Injection Rate - Case 1
0
1000
2000
3000
4000
5000
6000
7000
8000
9000
10000
0 5000 10000 15000 20000 25000 30000 35000 40000 45000
Time (s)
Tota
l Liq
uid
Rate
(st
b/d
)
OLGAPROSPER
5.5" ERD Well95% Watercut8 mmscf/d Gas Rate1595 psia Injection 232 psia THP2538 psia Pres
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Effect of Injection Rate on Stability
0
5000
10000
15000
20000
25000
0 5000 10000 15000 20000 25000 30000 35000
Time (s)
Tota
l Liq
uid
Rat
e (s
tb/d
)
OLGAPROSPER
5.5" ERD Well95% Watercut2 mmscf/d Gas Rate1595 psia Injection 232 psia THP2538 psia Pres
0
1000
2000
3000
4000
5000
6000
7000
8000
9000
10000
0 5000 10000 15000 20000 25000 30000 35000 40000 45000
Time (s)
Tota
l Liq
uid
Rat
e (s
tb/d
)
OLGAPROSPER
5.5" ERD Well95% Watercut4 mmscf/d Gas Rate1595 psia Injection 232 psia THP2538 psia Pres
0
1000
2000
3000
4000
5000
6000
7000
8000
9000
10000
0 5000 10000 15000 20000 25000 30000 35000 40000 45000
Time (s)
Tota
l Liq
uid
Rat
e (s
tb/d
)
OLGAPROSPER
5.5" ERD Well95% Watercut8 mmscf/d Gas Rate1595 psia Injection 232 psia THP2538 psia Pres
Severe Slugging Intermittent Slugging Steady Flow
(low rate) (mid rate) (high rate)
2 MMscf/d 4 MMscf/d 8 MMscf/d
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0
1000
2000
3000
4000
5000
6000
7000
8000
9000
0 50 100 150 200 250 300 350 400
Wellhead Pressure (psia)
Liq
uid
Rate
(st
b/d
)Effect of Wellhead Pressure on Stability
4 mmscf/d injection rate95% Watercut
Steady State
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Effect of Wellhead Pressure on Stability – Case 1
Intermittent SluggingRegion
Surging Region Severe SluggingRegion
OscillatingRegion
S-SRegion
0
0.2
0.4
0.6
0.8
1
0 50 100 150 200 250 300 350 400
Wellhead Pressure (psia)
Slu
g F
requency
(1/h
our)
0
20
40
60
80
100
120
140
160
180
200
Slu
g S
ize (
stb)
Slug FrequencySlug Size
4 mmscf/d gas rate95% Watercut
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Steady Surging (Case #1)
0
2000
4000
6000
8000
10000
12000
14000
0 5000 10000 15000 20000 25000 30000 35000
Time (s)
Tota
l Liq
uid
Rate
(st
b/d
)
WHP - 15 psiaWHP - 75 psia
4 mmscf/d gas rate95% Watercut
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Intermittent Oscillating (Case #1)
0
2000
4000
6000
8000
10000
12000
14000
0 5000 10000 15000 20000 25000 30000 35000
Time (s)
Tota
l Liq
uid
Rate
(st
b/d
)
WHP - 200 psia
WHP - 270 psia
4 mmscf/d gas rate95% Watercut
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Oscillating Severe (Case #1)
0
2000
4000
6000
8000
10000
12000
14000
0 5000 10000 15000 20000 25000 30000 35000
Time (s)
Tota
l Liq
uid
Rate
(st
b/d
)
WHP - 300 psia
WHP - 370 psia
4 mmscf/d gas rate95% Watercut
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Effect of Wellhead Pressure on Stability – Case 1
Intermittent SluggingRegion
Surging Region Severe SluggingRegion
OscillatingRegion
S-SRegion
0
0.2
0.4
0.6
0.8
1
0 50 100 150 200 250 300 350 400
Wellhead Pressure (psia)
Slu
g F
requency
(1/h
our)
0
20
40
60
80
100
120
140
160
180
200
Slu
g S
ize (
stb)
Slug FrequencySlug Size
4 mmscf/d gas rate95% Watercut
SS/Surge Flow Intermittent Slugging Severe Slugging
(lo WHP) (medium WHP) (higher ID)
Effect of Orifice Port Size on StabilitySteady Flow Intermittent Slugging Severe Slugging
(small ID) (medium ID) (large ID)
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Effect of Orifice Port Size – Case 1
0
2000
4000
6000
8000
10000
12000
14000
16000
18000
20000
0 5000 10000 15000 20000 25000 30000 35000 40000 45000
Time (s)
Tota
l Liq
uid
Rate
(st
b/d
)
0.25" Valve0.5" Valve1" Valve1.5" Valve
5.5" ERD Well95% Watercut4 mmscf/d Gas Rate1595 psia Injection 232 psia THP2538 psia Pres
Choked at ~2 mmscf/d
2334 stb/d5654 stb/d5312 stb/d3553 stb/d
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Gas Lift Instability – Case 2
CT gas lift for a deepwater GoM well is proposed.
In addition to stability issues, hydrate formation is a major concern.
OLGA is used to calculate the pressure and temperature transients during the CT gas lift shut-down period and the resultant effect on fluid temperature and hydrate formation.
Hydrate Cool-Down Time
Time after shut-in when the first hydrate is formed anywhere in the system.
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Well Characteristics - Case 2
• 4“ production tubing
• Production Fluid– 1455 scf/stb GOR– 29.2 oil API– 0.734 gas SG– 0 ppm water salinity
• Gas lift– 2 3/8” OD coiled-tubing gas lift at 5921 feet MD – four-port (½“ ID) bit– constant gas injection rate– 0.7 gas SG
0
2000
4000
6000
8000
10000
12000
0 1000 2000 3000 4000 5000 6000
Horizontal Distance (feet)
TV
D (
feet
)
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OLGA Well Model – Case 2
• Model setup
– WELL module used for inflow
– constant source boundaries at tubing head and casing head
– Orifice ID = 1”
Well
QQQQ
Coiled-Tubing Annulus
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Well Head Pressure - Case 2
0
500
1000
1500
2000
2500
0 5 10 15 20 25 30 35
Gas Injection Rate (mmscf/d)
Well
Head P
ress
ure
(psi
a)
3000 stb/d
5000 stb/d
10000 stb/d
50% Watercut
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Gas Injection Pressure - Case 2
0
1000
2000
3000
4000
5000
6000
7000
0 5 10 15 20 25 30 35
Gas Injection Rate (mmscf/d)
Required I
nje
ctio
n P
ress
ure
(psi
a)
3000 stb/d
5000 stb/d
10000 stb/d
50% Watercut
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Well Head Temperature - Case 2
100
110
120
130
140
150
0 5 10 15 20 25 30 35
Gas Injection Rate (mmscf/d)
Well
Head T
em
pera
ture
(F
)
3000 stb/d
5000 stb/d
10000 stb/d
50% Watercut
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Cooldown Time to Hydrates - Case 2
0
0.5
1
1.5
2
2.5
0 5 10 15 20 25 30 35
Gas Injection Rate (mmscf/d)
Coold
ow
n T
ime t
o H
ydra
te F
orm
atio
n (
hours
)
3000 stb/d
5000 stb/d
10000 stb/d
50% Watercut
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Conclusions
Transient flow calculation is a valuable tool for gas lift design and analysis to evaluate non-steady effects
– Gas Lift stability analysis
• Effect of injection gas rate, orifice size and wellhead pressure
• Needs improved valve models for unloading, multi-pointing, stability related to unload valve problems
– Gas Lift flow assurance studies
• Cooldown to hydrate formation
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