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Gas Lift
Lecture 11a- Gas Lift, Section 1 - Principles
Recommended Texts: Handout and
rt c a t et o s,
Kermit E. Brown, Volume 2a
PennWell Publishing Co, Tulsa, OK, 1980
Akim Kabir
Senior LecturerDepartment of Petroleum Engineering
Curtin University of Technology
Slide 1Section 1 - PrinciplesAug 2008
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Gas Lift
y s rt c a t ee e
Well quit
Production declines with depletion of reservoirenergy
Water cut increases Maximize production from naturally flowing wells
Note that this is different from gas injection for pressure maintenance
Injection of gas or water into reservoir to maintain reservoirpressure
Improve recovery
Slide 2Section 1 - Principles
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Gas Lift
Pi
Qi Reservoir Pressure
,
artificial lift
is required to
a er u
WC1restore or
increase
pro uct onProductionProduction
time t1
Slide 3Section 1 - Principles
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Gas Lift
Gas lifting
Continuous
Chamber lift
Plun er lift?
Plunger Lift
Rod um in
Electrical Submersible pumping
Progressive Cavity pumping
Slide 4Section 1 - Principles
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Gas Lift
Continuous
Intermittent
A Continuous
Gas Lift System
Low Pressure gas
FTHPProduced Fluids + Lift Gas
Separator
High Pressure Gas
CHP
as t ompressor
Liquid
Slide 5Section 1 - Principles Pwf
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Gas Lift
Open Semi-closed Closed
Slide 6Section 1 - Principles
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Gas Lift
Gas
vaves
closed All valvesclosed
Bottom valveopen
Fluid from formationhas built up above
Bottom valve opens andslug is propelled toward
Bottom valve closeswhen slug reaches the
Slide 7Section 1 - Principles
the bottom alve. the surface surface
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Gas Lift
-Production
as
Only bottomvalve is o en All valves
closed
Fluid from
formation has
All valves
below the slu
Valves close
when slugbuilt up abovethe bottom
open as slugmoves toward surface
reaches thesurface
Slide 8Section 1 - Principles
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Gas Lift
The injected gas aerates the fluid column and reduces
the density of the fluid
e ens y o e co umn re uce , o om o e
pressure gets lower and less reservoir pressure is
re uired to ush the l i uid to surface.
In other words the hydrostatic back pressure to thereservoir is reduced and the reservoir pressure can
overcome this reduced pressure and initiates the well to
flow.
Slide 9Section 1 - Principles
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Gas Lift
GL 'ed Dua l Com p le t ion - An Examp le
MIN I.D.STATUSSHORT STRING
DEPTH
Loca t i on :Wel l : XX
Wel lhead : MCEVOY DUAL (REFURBISHED)
Standard Wel l Type : X3123 7" LINER
DEPTHLONG STRING
M IN I.D . S TA TU S
Compl et ion Date : 1 .1. 2004
Max. Deviat ion : 43 deg @ 7131 f t
A ll De p th s in FT. AH.B THF
BTHF = 44 FT BDF (T6)Tubing : 3 .1/2" x 9.2 # New VAM, L80
Tubing tails: 2.7/8" x 6.4 #, NSCT, 2.3/8" x 4.6 # NSCT
f t . f t .
in
3.1/2" XXO-NIPPLE
3 .1 /2 "KBUG
3.1/2 " KB UG
3.1/2 " KB UG
3.1/2 " KB UG
3.1/2" XXO-NIPPLE 399437
1066
1759
2355
2856
BKR-5
BKR-5
DK-13 .1 /2 " K BUG4459
3.1/2" FLOW COUPLING3.1/2" FLOW COUPLING
2.8132.813
2.875
3 .1 /2 " K BUG5857
2.9102.910
3 .1 /2 " K BUG
3.1 /2 " K BUG
945
1667
DK-1
B K R - 5
3 .1 /2 " K BUG
3.1 /2 " K BUG
2230
2763
DK-1
B K R - 5
3.1/2" K B UG 4366B K R - 5
2.875
3.1/2" KB UG 5764B K R - 5
3.1/2" KB UG 6549DKO-23 . 1/ 2" K B U G6674
BKR-5
BKR-5
BKR-5
DKO-2.
X67043.1/2" X-NIPPLE (CAMCO)2.750
6737 9.5/8" RDH PACK ER (40-47#)
67732.7/8" CMD SSDCLOSED
V67 01 3.1/2 " C MD -S SD
68092.7/8" XN-NOGO NIPPLECHAM FERED BTM (CAM CO)
NO PLUG
2.313
2.205
2.750
3 .1/2 " LOCKABL E COLLET 6737
67473.1/2" x 2.7/8 X-OVER2.441
2.900
2.900
TOP OF T IE BACK PKR 6913
NO PLUGCLOSE
CLOSED7977 3.1/2" CM D-SSD 2.750
8013 3.1/2" x 2.3/8" X-OVER 1.901
8275
8277
8074
8080
8095
8161
8162
36 - Q1.0 - 8180 - 9196, 8214 - 8216
36 - Q1.5 - 8244 - 8246, 8254 - 8258, 8264 - 8274
SBS (4 " NU8RD)
4" WWS TELL TALE
3.250
3.423
OTIS 7 " WD 4 .5 " x 4 .0 "
4 " GPE
4 .1/2 " BLA NK CASING
4.5" LT C x 4 " NU8RD XO
4" WWS
4.000
4.000
3.875
3.423
3.423
8267 2.3/8" TBG SEAL ASSY 1.901
9.5 /8" CSG SHOE 7212
8285
8291
OTIS 7 " WD 4 .5 " x 4 .0 "
SB E
4.000
3.250
+ 15 SEAL UNITS SIZE:3.25"
2 .3 /8 " LOC TB G SEALAS SY + 1 5 S EA L UN ITS
I : "
1.901
OTIS 7" WD 4.5" x 4.0"
4 " GPE
4 .1/2 " BLA NK CASING
4.5" LT C x 4 " NU8RD XO
4" WWS
4.000
4.000
3.875
3.423
3.423
10489
10485
10509
10572
10573OPEN2.3/8" XD-SSD 1.875
10683
10653
SBS (4 " NU8RD)
4" WWS TELL TALE
SB E
I " " "
3.250
3.423
3.000
10676
10678
10685
36 - S8.3/8.4 - 10588 - 10672
I : .
2.3/8" XN-NOGO BXP
2.3/8" x 6 ' PERF. PUP
2.3/8" W/LINE RE-ENTRY
GUIDE + DROP-OFFBULLNOSE
10753
10756
10764
2.3/8" X-NIPPLE
PXN PLUG
10717X 1.875
I . .. 106 7
36 - S9.3 - 10757 - 10772
36 - S10.1 - 10793 - 10822
4" GPE
4 .1/2 " BLA NK CASING
4.5" LT C x 4 " NU8RD XO
4" WWS
4.000
3.875
3.423
3.423
10693
10708
10741
10742
SBS (4 " NU8RD)
4" WWS TELL TALE
BULL NOSE ASSY
3.250
3.423
3.403
10824
10826
10833
1.791
1.901
1.901
Slide 10Section 1 - Principles
10891LANDING COLLAR
7" CSG SHOE
Designed BY :
DATE : 09 /08 /01 (MARLINE)
CHECKED: 10 /05 /01 (ESMERALDA)
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Gas Lift
INJECTION GAS
No gas injection; Well is Dead
PRESSURE (PSI)500 10000
Dummy
Fluid Level
500
CASING PRESSURE
Dummy 1000 TUBING PRESSURE
Valve 1
Valve 2
EPTH(
FTT
VD)
1500
2000
Valve 3
Orifice 2500
3000
Pr
Slide 12Section 1 - Principles SIBH
P
=
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Gas Lift
FTHPProduced Fluids + Lift Gas
as ys em
Low Pressure gas
bubbling up
the well,
lightening the
fluid column in
Gaslift Compressor
High Pressure Gas
t e we
CHP
Separator
Liquid
Lift gas injectedat the deepest
mandrel
Slide 13Section 1 - Principles
Pwf
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Gas Lift
PRESSURE (PSI)500 10000
Well Flowing
INJECTION GAS Dummy
Fluid Level
500
CASING
Press
TUBING
Press.
Dummy 1000
Valve 1
Valve 2
1500
2000
Valve 3
Orifice 2500
3000
Slide 14Section 1 - PrinciplesPr
Pwf
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Gas Lift
A Well Bein Gas Lifted
PRESSURE (PSI)
0
500 10000
Well Flowing
INJECTION GASDummy
Fluid Level
500
CASING
Press
TUBING
CASING PRESSURE
Dummy 1000
.
Valve 2
1500
2000
a ve
Orifice 2500
3000
3500
Slide 15Section 1 - PrinciplesPr
Pwf
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Gas Lift
To enable the well that wil l not flow naturally
to produce o ncrease pro uc on ra es n na ura ow ng
wells
To remove or unload fluids from gas wells.
Slide 16Section 1 - Principles
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Gas Lift
us ave a source o gas
Imported gas from other fields may result in start up
problems Possible high installation cost
Top sides modif ications to existing platforms
Bottomhole pressure can not be reduced too much,since backpressure of two phase flow up the tubing has
.
Significant effort required to operate effectively
Can be too forgiving Quite inefficient (energy)
Slide 18Section 1 - Principles
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Gas Lift
-
Continuous f low is similar to natural flow and isachieved b controllin the in ection of as into thefluid column to cause aeration from the point ofinjection
Advantages: Takes full advantage of the gas energy available at the
surface
g er pro uc on vo ume
Equipment can be centralized Valves can either be wireline or tubing retrieved
Disadvantages:
Must have a continuous source of gas. a es o e a ove p or e c en ng. Bottom hole producing pressure increases both with
depths and volume
Slide 20Section 1 - Principles
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Gas Lift
- Intermittent flow is by injecting gas of suff icient volume and
surface, this usually require high gas rate to reduce the liquidfallback. The liquid to surface is in slug or piston form.
Advantages: Can obtain lower producing bottom hole pressure than
continuous flow and at low rates.
Suitable for well with production below 150 bpd (low P.I wells)
Can remedy wax deposition in tubing for waxy crude
Disadvantages: Limited in volume.
Causes surge on surface equipment. Equipment must be designed to handle the surge.
Cause interruption to other flowing wells in the productionsystem
Slide 21Section 1 - Principles
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Gas Lift
or ow ro uc on e s, n erm en ow gas s abetter Choice.
BFPD)
- -
2-7/8 TUBING - 200 TO 300 BFPD 3-1/2 TUBING - 300 TO 400 BFPD
3 Main Categories - Intermittent gas lift
- Chamber lift - Plunger lift ? (can be used without gaslift as well)
Slide 22Section 1 - Principles
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Gas Lift
Injecting gas into the well reduces weight of the fluid
column and conse uentl reducin the flowin bottom holeProduced Fluid + Lift Gas
pressure. (Optimal product ion)
1900
Optimal injection
point
1600
1500
Q1 =2000 b/d
Inj. Gas = 1mscf/d
w
Qliq500 2000 2200
Non Optimal lift ing
w = ps g
Q1 =2200 b/d
Inj. Gas = 2mscf/d
At high draw-down i.e. high gas in ject ion rate:
1) Non-darcy flow in IPR
2) Causes increase in the frict ional losses in the tubing
Slide 23Section 1 - Principles
thus offsetting the reduction of weight in the fluid
column.
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Gas Lift
A wells ability to produce fluid
a reduction in bottom hole pressure i.e.
theP(Reservoir Bottom Hole)
Slide 24Section 1 - Principles
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Gas Lift
Required Data
Static Bottom Hole Pressure
Pressure in the wellbore at the perforations under-
SBHP, Pr, Ps
Flowin Bottom Hole Pressure
Pressure in the wellbore at the perforations with thewell producing at a given rate
, ,
Drawdown
Change in pressure from static to flowing SBHP-FBHP = P
Fluid Rate
Slide 25Section 1 - Principles
e test per orme w e runn ng survey =
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Gas Lift
One way to quantify a wells productivity
is to use a relationship known as:
production rate and drawdown (rate and
ressure
Slide 26Section 1 - Principles
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Gas Lift
PI = BLPD / P
Drawdown
=
BLPD = P * PI
Slide 27Section 1 - Principles
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Gas Lift
ne way o p o e ro uc v y s n erms o ro uc v yIndex (PI)
The PI is a convenient term to compare performance between.
SBHP
BHP
PI is expressed in terms of rate versus drawdown (bpd / psi)Rate
Slide 28Section 1 - Principles
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Gas Lift
RELATIONSHIP
We have another curve to describe the inflow into the well
from the formation. This is theinflow curve
(inflow, .
P
B
Rate
Slide 29Section 1 - Principles
G Lift
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Gas Lift
RELATIONSHIP
The inflow curve can be derived using any two points. Normally
the SBHP is given as one point. e oge curve s one n ow re a ons p:
Q/Qmax = 1 - 0.2(FBHP/SBHP) - 0.8(FBHP/SBHP)2
where FBHP and Q are measured data (normally from a surveyand a concurrent welltest).
H
P
SBHP
B
Q
FBHPQmax
Slide 30Section 1 - Principles
Rate
G Lift
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Gas Lift
PI is a more simple way to handle inflow.
IPR is more complex, and more correct than, u requ res e er a a o correc ycalculate
P
B PI
Rate
Slide 31Section 1 - Principles
Gas Lift
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Gas Lift
we compare e n ow mo e an e ou ow mo eby drawing them on the same graph, we can find the
expected flow rate and FBHP.
BH
P
FBHP
Rate This technique is the basis for more complex predictions
such as the equil ibrium curve and the lift gas performancecurve.
Slide 32Section 1 - Principles
Gas Lift
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Gas Lift
Inflow: Pwf = Pres dPres dPperf
Outflow: Pwf = Psep + dPfl + dPtbg
TGLR3Inflow OutflowTGLR2
BHP
TGLR3 > TGLR2 > TGLR1
Rate
Slide 33Section 1 - Principles
Gas Lift
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Gas Lift
900)
n m e as or max mum
flowrate is desired
2) Limited Gas or the most
600
700
on(BPD econom ca ra e s es re
1) Production is fixed
Water /gas coning
300400
rodu
cti
Sand production
Governmentregulations
321
0
100Net
Gas lift Injection (Mscfd)
Slide 34Section 1 - Principles
Gas Lift
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Gas Lift
Qinj
production as we approach maximum point
700
800
900
BPD) Optimum Injection Point Qliq
400
500
600
uctio
n(
Sub-optimum in jecting points
100
200
300
N
etPro
0
50 100 200 300 400 500 600 700 800 900 1000
Gas lift In ection Mscfd
Slide 35Section 1 - Principles
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