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Gas Lift
Gas Lift
• Gas lift is an artificial lift method whereby external
gas is injected into the produced flow stream at
some depth in the wellbore.
• Gas lift utilizes the energy of compression in a high
pressure gas to decrease the hydrostatic gradient in a
liquid column and thus cause the column to flow to
surface.
• This process is accomplished with the use of gas lift
valves, which acts as a pressure regulator.
Gas Lift
Gas Lift
• Early applications of gas lift resulted in a study of efficiencies, and four gas injection rates that were significant in the operation of gas-lift installations were found:
1. Injection rates of no flow, where the amount of gas flowing up tubing is insufficient to lift the fluid.
2. Injection rate of maximum efficiency, where a minimum volume of gas is required to lift a barrel of fluid.
Gas Lift
3. Injection rate of maximum flow, which will
yield maximum production.
4. Injection rate of no flow due to excess gas,
which is reached when the friction produced which is reached when the friction produced
by the gas prevents fluid from entering the
tubing.
Gas Lift Application
• There are four categories of wells to be
considered in gas lift application:
1. High productivity index (> 0.5)
2. High bottom-hole pressure wells2. High bottom-hole pressure wells
3. Low productivity index (≤ 0.5)
4. Low bottom-hole pressure wells
Note: High bottom-hole pressure will support a fluid
column equal to 70% of the well depth; and low
BHP will support a fluid column less than 40%.
Two Types of Gas Lift
I. Continuous Gas Lift
– Continuous injection into the tubing or casing at some predetermined depth to reduce the pressure opposite the producing formation. The injected gas mixes with the formation gas to lift injected gas mixes with the formation gas to lift the fluid to the surface by one or more of the following processes:
• Reduction (lower fluid density)
• Expansion (expanding gas)
• Displacement (liquid slugs by large bubbles)
II. Intermittent Gas Lift
– Injection of gas at a high instantaneous rate for a
short period, with ejection of a slug of fluid up the
tubing at controlled time intervals.
– Individual well conditions will dictate the optimum
time for conversion from continuous to
intermittent; some good rules of thumb to use to intermittent; some good rules of thumb to use to
estimate the best time for the conversion are
listed below.
Valve Mechanics
• Gas lift valves are constructed where all
components must be fitted into a small
cylindrical shaped tube. A typical valve
must have a closing force, an opening
force, and a flow regulating orifice. force, and a flow regulating orifice.
– If tubing pressure causes gas flow
regulation, it is referred to as a tubing or
fluid operated valve.
– If casing pressure causes gas flow regulation,
it is referred to as a casing or gas operated
valve.
Figure 1
Example of conventional
gas lift valve mandrel
Casing and Tubing Valves
Valve Mechanics
• Gas lift valves operate in accordance with certain basic principles, and are mostly compared with pressure regulators. The component parts are:
1. Body
2. Loading Element2. Loading Element
• Spring, gas, or combination of both
3. Responsive Element
• Metal bellows, piston, or rubber diaphragm
4. Transmission Element
• Metal rod or rubber diaphragm
5. Metering Element
• Orifice or port
Opening Pressure of Valve Under
Operating Conditions.
• The force balance for valves (figure 6.11b) which are
closed, but on the verge to opening will be
oc FF =F is the force in Fc is the force in
pounds holding the
valve closed and Fo
is the force in
pounds trying to
open the valve.
Figure 6.11
Force Equations
• Substituting terms for Fc and Fo,
( ) ApAApF +−=
( )vbtbtTc AASApF −+=
( ) vtvboo ApAApF +−=
pb = Pressure inside the bellows at 60 oF (psig)
pbt = Pressure inside the bellows at operating temperature, (psig)
Ab = Total effective bellows area, (in2)
po = Casing pressure causing valve to open, (psig)
pvo= Casing pressure causing valve in a valve tester, (psig)
pt = Tubing pressure acting on the valve, (psig)
Av = Area of the valve port, (in2)
ST = Effective spring tension (psig)
Where:
• Setting these expressions equal, dividing by Ab, and solving for po,
The term p /(1-A /A ) is the pressure necessary to
( ) ( )
−−+
−=
bv
bvtt
bv
bTo
AA
AApS
AA
pP
/1
/
/1
[pressure to open] = [bellows effect] + [spring effect] – [tubing effect]
The term pbT/(1-Av/Ab) is the pressure necessary to overcome the bellows charge at operating pressure. The full effect of the spring, St, must be overcome. The tubing effect (T.E.) on the opening pressure of the flow valve when the tubing pressure opposite the valve is known is
( )
−=
bv
bvt
AA
AApET
/1
/..
Opening Pressure of Valve
• In a valve tester, the tubing pressure opposite the valve is zero. With a force balance, opening and closing forces are equated,
( ) ( )vbtbbvbvo AASApAAp −+=−
– Or
– Or, in terms of pb
( ) t
bv
bvo S
AA
pP +
−=
/1
( ) ( )vbtbbvbvo AASApAAp −+=−
( )( )bvtvob AASpP /1−−=
Closing Pressure of valve under
operating conditions.
• The valve is now open and ready to close, and the
casing pressure is operating over the total effective
bellow area (figure 6.11c). The force balance is
FF = oc FF =
Closing Pressure
• Setting these expressions equal, dividing by A , and
bvco ApF =
( )vbtbtTc AASApF −+=• Substituting terms for Fc and Fo,
• Setting these expressions equal, dividing by Ab, and
solving for pvc,
• The valve closing pressure in a tester (where the
tubing pressure is zero) is
( )bvttTvc AASpP /1−+=
( )bvvovc AApP /1−=
• Since at charging conditions the tubing effect
is zero, the pressure to open the valve consists
of the bellows and spring effects. The bellows
of most valves are charged at 60oF and the
volume is assumed constant. The bellows
pressure at operating conditions is found by
( ) ( )60460460)60(
)60(
+=
+F
Fb
vT
bT
o
o
Z
p
TZ
p
pbT = Pressure inside the bellows at operating temperature, (psig)
pb = Pressure inside the bellows at 60 oF (psig)
Zt, Z60= deviation factors
Tv = temperature at the valve
Valve Spread
• The difference between the opening and
closing pressures of a bellows-type valve, Δp,
is call the spread and is a measure of the
deference between the effective area of the deference between the effective area of the
bellows and area of the port.
• The spread Δp is equal to the opening
pressure minus the closing pressure, or
−
−+
−=∆ t
b
vtbT
bv
bv pA
ASp
AA
AAP 1
/1
/
Static Gas Column Pressures
• Accurate calculation of the gas injection
pressure at any depth is essential for
designing and analyzing most gas-lift
installations. The gas pressure at any depth in installations. The gas pressure at any depth in
terms of the operating pressure at the casing
wellhead is
=
avgavg
whvTz
Dpp
γ01875.0exp
Pv = casing pressure at valve depth, psia γ = gas specific gravity (air = 1.0)
Pwh= gas pressure at the wellhead, psia D = depth to valve, ft
Tavg= average temperature of gas column, oR
Zavg= compressibility factor avg. pressure and temperature of gas column.
• If the temperature of the total depth is known, the temperature at any depth is calculated from the temperature gradient. For the Gulf Coast area, if the temperature is unknown it can be estimated from
Tv = 0.015D + 80oF
-Where T and D is the temperature and depth of the -Where Tv and D is the temperature and depth of the valve in feet.
• Before the average pressure can be calculated, the pressure increase of the static gas column due to its own density must be estimated from
Δp = 0.25(pwh/100)(D/100)
Flowing Gas Column Pressure
• For small conduit wells (3/4-, 1-, and 2-in.
combinations) where frictional pressure losses
may be significant, the pressure drop of the
lift gas is critical. Buthod and Whitely lift gas is critical. Buthod and Whitely
developed an equation for calculating the
pressure traverse of downward flowing gas,
AApBp civ +−= )( 22
Buthod and Whitely
psia pressure,injection surface
psia at valve, pressure subsurface
22 )(
==
+−=
p
p
civ
ci
v
AApBp
( )
ft depth, D1.0) (airgravity specific gas γ
MSCF/day rate, flow gas qin. diameter, channel flow equivalent d
factor)(friction 1051.1A
factor)ght column wei (gas 0.376
exp B
23.5
2
5
===
==
××=
=
−
d
Tqz
Tz
D
avgavg
avgavg
ci
γ
Well Unloading
• Unloading simply means removing all the casing (packer) fluid left in the well between the tubing and casing at the time of completion and replacing it with gas down to the point of injection.injection.
• As the injection pressure is applied to the annulus (shown on Fig 6.15), all valves in the tubing string are opened and the fluid is displaced through the open valves into the tubing and , in open-type installations, is U-tubed around bottom.
Valve Spacing
• The proper spacing of gas lift valves is
determined by writing a force or pressure
balance for the valve. The depth of the first
valve depends upon the injection pressure valve depends upon the injection pressure
available, the static fluid gradient, static fluid
level of the well, i.e..
Single Operating Depth Method
• The depth of the first valve can be determined
by
11 DPDP gciwts σσ +=+
• Or graphically (next slide)
Pts = surface tubing pressure in psig
Pcs = surface casing pressure in psig
σw = water density in psi/ft
σg = average gas density in psi/ft
D1 = depth to first valve in ft
Single Operating Depth Method
• Once this first valve have been uncovered, it can be used to reduce the hydrostatic pressure in the tubing above that point by gas injection. Reduction of the hydrostatic pressure simply means that a second valve can be run below and the casing gas pressure will push the packer fluid down, through the second valve so it can be lifted to the surface by the first valve. Again, the depth down, through the second valve so it can be lifted to the surface by the first valve. Again, the depth to the second valve is determined by a pressure balance condition given by
2121min )( DPDDDP gcswts σσσ +=−++
σmin = average minimum two-phase gradient that can
be developed by the first valve (psi/ft).
Setting Depth (Graphically)
Single Operating Depth Method
• This process would continue to locate subsequent
valve depths until the casing pressure (right side of
the equation) can no longer produce the minimum
gradient.
• At this point, another definition is needed, that of
the deepest point of injection. This depth is defined
by the equation
FBHP - σavg(DT - Div) = Pcs lift + Divσg
σavg = Average flowing gradient in the tubing from the perforations to the lift valve (psi/ft)
Dt = Total depth of the well to the perforations (ft)
Div= Depth to the injection valve (ft)
Pcs lift= Surface casing pressure operating the lift valve (psig)
• When the first valve is uncovered, it will lighten the
fluid column above because a temporary lifting
gradient from the first valve is created when water
enters the tubing from lower valves. This temporary
gradient will become lighter and approach the final
lifting gradient but not reach it due to the valve
closing tubing pressure. Consequently, the depth to closing tubing pressure. Consequently, the depth to
the second valve is found by the condition where
Where,
PTG = total pressure difference of temporary gradient in psi
Psafety = small margin to ensure flow through valve in psi
Pts + PTG + Psafety + σw(D2 - D1) = PCS + σgD2
Tubing Operated Valve Example
• The well is 10,000 ft deep (2-7/8” tubing) with a
shut-in bottomhole pressure of 4000 psig and a
measured PI of 1.33 bfpd/psi. The well flows
20% oil (30° API) and 80% water (specific
gravity of 1.07). The surface pressure during lift gravity of 1.07). The surface pressure during lift
is expected to be 50 psig, and the available gas
pressure is 1000 psi (approximately 0.025 psi/ft
increase due to density). The bottomhole
temperature is 2000F and the expected flowing
temperature is 1000F. The design flow rate is
800 bfpd.
De
pth
(1
00
0 f
t)
1st valve: 2000’
2nd valve: 3200’
3rd valve: 4000’
Surface
pressure
Injection fluid 0.45 psi/ft
De
pth
(1
00
0 f
t)
FBHP
SIBHP
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