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