new gas lift valve design

8/18/2019 New Gas Lift Valve Design

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SPE 36597

New Gas Lift Valve Design Stabilizes Injection Rates: Case Studies

T. Tokar, Chevron, Z. Schmidt, University of Tulsa, SPE, and C. Tuckness, Halliburton Energy Services

Copyright 19S6, Society of P@troleum Enginaars, Inc.

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Abstract

Optimization of production

in continuous gas lift wells is

difficult to achieve when unstable flow (tubing or casing

heading) causes gas lift injection rates to fluctuate. This prob-

lem, which occurs when there are variations in casing and (ubing

pressures, is particularly prevalent in a field with multiple wells

drawing upon a single source for injection pressure. Square-

edged orifice valves with a simple cylindrical channel have

traditionally been employed as operating valves to transport the

gas. Gas flow through the channel is usually in the subcritical

flow regime. The injection rate from the casing to the tubing

fluctuates with the tubing pressure, even with a constant casing

pressure, allowing injection rates to be affected by both the

casing and tubing pressures. With this type of symmetric flow

geometry, critical flow (known as sonic flow velocity) will occur

when the down-stream pressure is z$()?io to 50% less than the

upstream pressure.

A new injection valve has been developed to ensure constant

injection rate from the casing to the tubing with constant casing

pressure, even when tubing pressure is only 10% less than casing

pressure. The laterally asymmetric internal geometry of the

nozzle-Venturi creates an injection valve that reaches critical

flow velocity with pressure differentials of only 10%. At critical

flow velocity, the injection flow rate becomes constant and is

controlled by casing pressure only. The new design is a 1-inch or

I-l/2-inch OD valve that fits into any standard side pocket

mandrel and can be deployed with standard slickline. A computer

software program has been developed to determine the proper

size orifice to output a specific flow rate at the given well

conditions.

Initial usage of the valve has shown that injection flow rates

will be constant if source pressure remains constant and tubing

pressure is 10 to 100 ZOess than the casing pressure.

Introduction

Unstable flow (casing heading) is a common occurrence in

continuous gas lift systems and can develop because the charac-

teristics of the system are such that small perturbations can

degenerate into huge oscillations in flow parameters.

Tubing Heading. Gilbert’ and Grupping et al.23were the first to

describe the mechanisms by which these unstable conditions are

generated. In many welIs, the operating gas lift valve is simply

an orifice valve and operates in the subcritical flow regime.

Under this flow condition, a temporary variation in tubing

pressure at the operating valve depth can result in an increase in

the gas injection rate through the gas lift valve, decreasing the

density of the production fluid. This in turn, decreases the tubing

pressure at the valve depth and increases the differential across

the valve, causing more gas to flow through the valve. The flow

from the reservoir will also increase as a result of the reduced

pressure in the tubing. This positive feedback process acceler-

ates until the casing pressure drops sufficiently, causing the

injection flow rate through the gas lift valve to decrease. As a

result of this process, the density of the fluid in the tubing string

increases, causing the production pressure to increase, and

subsequently, a reduction of reservoir fluid entering the wellbore.

These conditions remain until the pressure in the annuhrs

increases sufficiently and the rate of gas injection through the gas

lift valve once again increases.

Operating a well under these cyclical conditions has several

disadvantages. First, gas and liquid flow rate surges (or slugs)

can occur. Coupled with pressure surges in the production

facilities, these surges may be so large thal severe operational

problems, which include difficult operation of the low pressure

separator or compressor shutdown, can occur.4 Second, the full

lift potential of the gas is not used, resulting in an inefficient

operation that consumes excessive quantities of gas. Third, in

traditional prevention of gas lift instability, either I) more gas is

injected than needed or 2) the flow is choked at the well head,

which reduces the inflow from the reservoir.4 Fourth, production

control and gas allocation become very difficult because of

casing and tubing pressure fluctuations. With this condition, it is

more difficult to determine reliable production rates when

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2 T.TOKAR,Z.SCHMIDT,and C.TUCKNESS

SPE36597

testing.

Blick

et al. Asheim and Alhanati et’al. developed

stability criteria from which design parameters could be selected

or modified. Traditionally, there have been three options

considered practical for field installation tomodify an existing

unstable installation. These are: l)increasing the injection gas

rate, which increases compression costs and results in uneconom-

ical production; 2)reducing port size, which requires a slickline

well intervention, will then require an increase in injection

pressure to pass thesame gas flowrate, and in addition, can

increase production costs by opening the unloading valves

(multipoint injection); or 3) choking at the surface, which will

reduce the total production output. Although each option has

obvious operational drawbacks, the first is normally chosen.

To avoid tubing instability and the significant reduction of

cost efficiency that results, operating stability should be ad-

dressed during the design phase of the well(s) by requiring

accurate stability criteria and/or by initiating changes in the

existing equipment that can stabilize these conditions.

Casing Heading. In order for casing instability to occur, the gas

lift valve must permit the gas injection rate to fluctuate as a

function of theproduction pressure (i.e. the flow through the

valve has to be in the subcritical flow regime). Critical flow

through a gas lift valve, on the other hand, would ensure a stable

casing injection rate that would be unaffected by the production

pressure.

Operating a gas lift

valve or orifice valve in critical flow has

not been attempted by previous investigators as a means of

eliminating instability because of

the

excessive pressure differen-

tials required to achieve this flow regime. For example, with an

injection pressure of 1,000 psi, a pressure differential of approxi-

mately 400 psi would be required to achieve critical flow

through

thevafve.This would require excessivecompressioncosts,which

would not be economical.

The Nozzle-Venturi Valve

The nozzle-Venturi gas-lift valve has essentially the same

elements as an orifice valve with the exception that the squrire-

edge orifice is replaced with a converging-diverging aperture.

F@me 1 is a cross-sectional view of the valve. Gas constrained

between the upper and lower packing enters the valve through the

inlet ports, passes through the converging section, the throat, and

the diverging section, and finally, exits through the outlet ports

into the production string. A check valve prevents reverse flow.

The nozzle-Venturi valve has been designed to operate

easily and efficiently in critical flow, and therefore, can prevent

flow instability by holding the gas injection rate constant.

Flow performance of the square-edge Orifice Valve

and the Nozzle-Venturi Valve

Figure 2 illustrates and compares the flow performances

of both

the

square edge orifice and the nozzle-Venturi valve and shows

both the critical and subcritical flow regimes. The flow rate and

the production pressure are plotted on the vertical axis and the

horizontal axis, respectively. Both flow performance curves are

generated by gradually reducing the production pressure to

atmospheric while maintaining a constant injection pressure. It

should be noted that the flow rate through both valves increases

with a decrease in production pressure (or an increase in the

differential pressure across the valve). This continues until a

critical flow at the critical pressure through a valve is reached.

The flow rate remains constant thereafter. The flow regime

between the injection pressure and the critical pressure is termed

“subcritical flow regime,” whereas the flow between the critical

pressure and the atmospheric pressure is termed “critical flow

regime.”

The main difference between the two gas lift valves is

that the critical flow for the standard orifice valve is reached at

a production pressure that is approximately 60% of the injection

pressure, whereas the nozzle-Venturi valve attains critical flow

at 90’70of the injection pressure. .

In order to explain the difference in the flow performance of

a square-edge orifice valve and the nozzle-Venturi valve, the

pressure profiles for both flow control devices are plotted in

Figure 3, The dotted line represents the pressure profile for the

square-edge orifice, and the full line comesponds to the nozzle-

Venturi flow control device. For an injection pressure of 1,000

psia, the sonic flow at the throat (the critical flow regime) is

established for both devices. For air flow, this corresponds to a

pressure of approximately 540 psia at the throat. This flow

condition results in the maximum mass flow rate as indicated by

points A & B in Figure 2 for the nozzle-Venturi and the square-

edge orifice respectively. After the throat, where the greatest

velocity and the lowest pressure occurs, the pressure increases

(recovers), and the velocity decreases in the direction of flow.

For the nozzle-Venturi, the maximum pressure of 900 psia is

attained at the exit of the divergent section. The pressure

recovery for the square-edge orifice is only slight, resulting in the

exit pressure of 600 psia. Therefore, the sonic flow for a nozzle-

Venturi valve can be achieved at a much lower pressure differen-

tial, resulting in a higher exit or production pressure as compared

to a square-edge orifice valve.

With pressure differentials of 100-200 psi across the

operating valve, (a common design condition that is used in the

gas lift industry), critical flow can almost always be achieved,

thus eliminating casing instability and minimizing tubing

instability. 9’1011

Concept Testing

A nozzle-Venturi valve with a set of flow curves was tested to

verify the concept that the orifice would reach critical flow

within 10% of the upstream pressure. This valve was the original

prototype tested per API 11V2. The test facility contained an air

compressor capable of pressuring a string of tubing to 2,0tXl psi.

A series of storage tanks held the volume needed to sustain the

test. At the beginning of the meter run, an adjustable choke

valve was used to maintain a constant upstream pressure, and a

standard meter run was placed directly downstream of the inlet

choke, The test fixture, which reproduced a pocket section of a

side pocket mandrel, was located downstream of the meter run.

Another adjustable choke, placed just after the test fixture,

controlled downstream pressure. A valve and latch assembly was

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SPE 36597 NEWGASLIFTVALVEDESIGNSTABILIZESNJECTIONRATES:CASESTUDIES

installed in the test fixture. The entire system was then pressured

to 1,400 psi, and pressure was equalized upstream and down-

stream of the test fixture, Upstream pressure was held constant,

and downstream pressure was decreased in increments of

approximately 10 psig Figures 4, 5, 6 . Upstream pressure,

downstream pressure, differential across the meter run, and

temperature readings were taken at each increment, The test was

repeated for 900 psi and 400 psi. The calculated flow rates were

plotted and the results verified that critical flow was established

within 109Zof the pressure differential.

After acceptance of the basic concept, a prototype of the

nozzle-Venturi orifice was made to retrofit into a square-edged

orifice valve design. The retrofit valve was placed in the same

fixture and tested with the same pressures. This valve had not

been internally optimized for the nozzle-Venturi orifice, and

though critical flow was reached within 10% of the upstream

pressure, the maximum flow rate was less than with the first

concept valve. The valve was then redesigned with optimized

upstream and downstream geometries and a new check valve to

maximize the flow rate of the nozzle-Venturi orifice. A new

prototype was built, and tests duplicating the earlier tests were

performed. The results showed that the new valve design

maximized the flow rate and maintained the critical flow

characteristics of sonic velocity with 10 ZOifferential,

Development of Sizes

The nozzle-Venturi orifice profile geometty isdefined by a series

of specific equations. These equations were programmed on a

computer, and the profile dimensions were generated for a range

of sizes with throat diameters varying in MM-inch increments.

A spread sheet of the profile dimensions of each size was entered

into the computer-aided-design system, and all possible profiles

were created parametrically. An initial set of nozzle-Venturi

orifices with throat diameters of. 125 inch, .314 inch, and .50

inch were built and tested. Each test was done in exactly the

same fixture with exactly the same pressures as were used when

the original concepts were tested. Flow curves were drawn from

the data, and the curves were compared (Figures 4, 5,6). Without

exception, every test resulted in critical flow when the down-

stream pressure was 1O%-100% less than the upstream pressure,

thus proving that flow rates of a given orifice could be accurately

predicted with flow equations. The computer software program

developed with these equations was written to predict either tbe

flow rate for a given throat diameter or the throat diameter for a

given flow rate. The actual test results were then modeled on the

computer flow rate predictor program, and the results were

accurate to within 590 of the actual test results.

Case History

Nozzle-venturi Field

Trial

in a Dual Well Application.

While

there is a general industry recognition that a dual well will

minimize expense to develop a field, it is also known that

efficiency in gas lifting is difficult. Because they share a

common wellbore, both strings of the completion must draw

upon the same high-pressure gas-lift supply in the annulus. In

addition, the producing intervals are usually at different pres-

sures, which compounds the difficulties. Typically encountered

in dual gas lift wells is the problem of disproportionate distribu

tion of gas into each tubing string. One production string wil

accept too much gas, which robs lift gas from the other,

Platform Gail is a part of Chevron’s Sockeye field and i

located 10 miles off the coast of Ventura, California, Th

platform has 24 producing wells, 15 of which are on gas lift. O

the gas lift wells, 2 are dual gas-lift completions. Well E-16,

dual gas-lift completion on Platform Gail, had a history of sub

optimal gas Iift performance,

A schematic of the E-16 wel

completion can be seen in Figure 7.

There are two basic factors influencing the poor gas lif

performance in E-16. First, the long string was taking too much

of the available gas in the annulus, Ieaving the short string

starving for more lift gas. Second, there was a heading problem

in the long string. If too much gas was supplied to the annulus

on the surface, the long string would begin to slug wildly and

produce sand. Because of the platform processing equipment

sensitivity to pressure fluctuations, a severely heading well could

shut the entire platform down. Consequently, gas lifting E-16 wa

a calculated risk.

Supplying too much gas would increase production from the

short string but would increase the long string’s heading and the

well would produce sand. Cutting back on the gas lift supply

minimized the long string’s heading but also restricted the

production from the short string. To best solve the problem

using available equipment, a compromise that would not upse

the platform’s processing equipment was finally reached;

however, the well then produced at sub-optimal fluid rates.

Performance Characteristics.

A better engineering design wit

proper orifice sizing was needed. The performance characteris-

tics of the nozzle-Venturi made itan ideal replacement choice fo

the current orifice valves in E-16. In particular, the nozzle-

Venturi’s insensitivity to tubing pressure meant that it could be

designed for specific injection rates and that fluctuations in the

tubing pressure opposite the point of gas injection would have n

influence on the gas throughput of the valves. Only the casing

pressure would influence the gas injection rate, This would solve

the problem of properly allocating gas to each of the production

tubing strings.

The Asheim’ stability analysis was run, and the results con

firmed that the long string was prone to heading. The current

orifice valves were designed to operate in subcritical flow. As the

slugs caused fluctuation of the tubing pressure, the orifice valve

gas throughput also fluctuated. By accentuating the tubing

pressure swings with increased and decreased gas injection, the

orifice valve was only magnifying the pressure swings at the

surface. In contrast, the nozzle-Venturi valve would act to

dampen the natural slugging tendencies of [he long string by

injecting a continuous amount of gas. With the nozzle-Venturi

assuming critical flow at just 10% below the casing pressure,

fluctuating tubing pressure opposite the valve could not change

the valve’s gas throughput. It was expected that the nozzle-

Venturi valve would allocate the proper amount of gas to both

strings while minimizing any heading in the long string as long

237


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4

T. TOKAR, Z. SCHMIDT,

and C,TUCKNESS

SPE36597

as the tubing pressure opposite the nozzle-Venturi valve was at

least 6% to 10% lower than the casing pressure at (he valve.

Design ing the Nozzle Venturi For I mngand Short S trings In

Well E 16

With predictable performance curves available,

designing the nozzle-Venturi valves for each string of a dual well

was simply a matter of deciding how much gas each string would

require, and then, sizing the valves accordingly to inject the

determined amounts of gas. In this test, both strings were already

operating on the bottom gas lift mandrel so there was no confu-

sion as to the depth of lift.

An inflow performance review was performed on each of the

completions using commercially available nodal analysis

software. Table 1 shows the input variables. The analysis

suggested that the PI for the short and long strings was 3.9 and

2.4, respectively. Figure 8 was then generated to predict the

production rates for various gas injection rates. Gas injection

rates prior to installation of the 2 nozzle-Venturi valves are

shown on the figure. The goal was to regulate the gas injection

volume to each of the strings while minimizing the heading in the

long string. With this in mind, the decision was made to design

the nozzle-Venturi valves to inject 600 MSCF/D into the long

string and 800 MSCF/f) into the short string. Casing pressures

could be set anywhere from 900 to 1,700 psig on the surface,

which afforded a certain amount of flexibility; i.e., the nozzle-

Venturi valve could be designed to inject 800 MSCF~ while

operating at a 1,500 psig surface casing pressure or to inject the

same amount with only 1,200 psig of surface casing pressure. In

either scenario, the most important consideration was ensuring

critical flow by maintaining enough differential across the valve.

Figure 9 depicts what the tubing pressures would be at the

nozzle-Venturi’s design gas injection rates. Both curves in the

figure were generated by simulating the pressure gradient in the

tubing strings at the expected liquid rates. The casing pressure

gradient is also shown for the highest achievable surface casing

pressure, which is 1,700 psig. As shown in the figure, it is

apparent that a 646 psi pressure differential between the short

string’s tubing and casing pressure at the location of the nozzle-

Venturi would exist. The differential achieves critical flow, but

it is also well in excess of the minimum differential necessary to

ensure critical flow. The differential is even larger for the long

string, The expected tubing pressure of the short string at the

nozzle-Venturi is 1,254 psig. Thus, to ensure critical flow, the

minimum casing pressure opposite the valve should be roughly

1,400 psig since a tubing pressure 10% less than the casing

pressure puts the nozzle-Venturi in critical flow. Ten percent of

1,400 psig is 140 psi, which corresponds to 1,260 psig for the

tubing pressure. Thus, 1,400 psig is the lowest casing pressure

at the nozzle-Venturi that would maintain the valve in critical

flow. It is important to note that 1,400 psig of casing pressure at

the valve corresponds to 1,200 psig for the surface casing

pressure.

Consequently, operating the casing pressure much

below 1,200 psig at the surface should not be considered.

As mentioned earlier, the casing pressure is the only factor

controlling the gas injection rate while the valves are in critical

flow. However, excessive casing pressure can also open other

valves in the gas lift string. The long string wasn’t a problem

because it only had one gas lift mandrel, but the short string had

4 gas lift mandrels, two of which contained dummies. The

second mandrel contained a live gas lift valve. A simple force

balance calculation was made to determine at what casing

pressure the valve in mandrel number 2 would open. The results

are displayed

in

Figure 10. Standardgas lift valves sense tubing

and casing pressure; thus, it was important that the tubing

pressure at the valve also be determined. A range of expected

tubing pressures at the second mandrel’s valve is displayed on the

figure and shows that if the surface casing pressure exceeds

1,860, the valve will open. Having established the working

surface casing pressure range to be 1,200-1,860 psig, the next

step was to size the nozzle-Venturi valves.

Orifice throat diameters of 0.14 inch and 0.129 inch ported

nozzle-Venturi were chosen for the short and long strings,

respectively. These sizes were selected because their injection

rates approximated the design rates at a surface casing pressure

of 1,400 psig, Because they were also prototypes, each valve

was tested in a flow loop to confirm predicted flow rates. Results

from those flow tests confirmed the theoretical predictions and

showed critical flow would exist when the downstream pressure

was

6 Z0-

10% lower than the upstream pressure,

Pi lot Tes t Resu lts Slickline operations to install the nozzle-

Venturi valves commenced on August 16, 1995, and well

production was resumed later that evening. Figures 11 and 12

are 4-pen charts showing casing and tubing pressures on the long

string before and after the nozzle-Venturi valves were run. The

static and differential pressures noted on the figures were used in

conjunction with a standard orifice plate to calculate the injection

volume.

Before installation of the two nozzle-Venturi valves, the

tubing pressure fluctuations, as shown in Figure 11, ranged from

110 to 230 psig on the long string. After installing the nozzle-

Venturi, the tubing pressure fluctuations were reduced to 110 to

160 psig. This represents a 60% reduction in the pressure range

over which the long string would slug. In a similar fashion,

Figures 13 and 14 are the short string’s 2-pen charts from before

and after installing the nozzle-Venturi valves. The tubing

pressure on the short string was reasonably steady before the

nozzle-Venturi’s installation. Note that the line designating the

tubing pressure is even steadier after the nozzle-Venturi’s

installation. The line is also thick, indicating an increased liquid

rate. Also, the tubing pressure is about 60 psi higher than it was

before, another sign that the fluid rate had increased.

Subsequent well testing revealed that the oil production from

well E-16 increased by 24y0 (500 BOPD). The decreased

heading, increased liquid rate, and successful lifting of the dual

completion strings all demonstrate the benefits of the nozzle-

Venturi valve. The well is also easy to troubleshoot.

Figure 15

was created to show how each nozzle-Venturi is performing,

based on the surface casing pressure. If the total measured gas

injection rate does not match the combined vaiue shown in

Figure 15, there is a potential problem with the existing gas lift

string(s).

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SPE 36597 NEW GAS LIFT VALVE DESIGN STABILIZES INJECTION RATES: CASE STUDIES

5

Nozzle-Venturi Injection Rate Prediction Test. One nozzle-

Venturi valve was used by a major European operator in a trial

program to test the capabilities of the flow profile. The trial was

to determine whether the nozzle-Venturi would pass more gas

with less casing pressure than a conventional square edged

orifice. Comparisons were to be made of theoretical and actual

well test data using a l/8-inch throat diameter nozzle-Venturi and

a l/8-inch throat diameter square edged orifice. They were each

installed in the top side pocket mandrel of the long string of a

dual well for the test.

A Thornhill-Craver curve was used to predict the flow

characteristics of the square edged orifice. A computer program

was used to predict the injection flow characteristics of the

nozzle-Venturi. Test data was taken with both valves and plotted

with the prediction curves. As shown on the chart in Figure 16,

both of the actual data curves show results of higher than

predicted casing pressure for a desired injection rate. However,

the nozzle-Venturi data curve was much closer to the prediction

than the square edged orifice. Also, the results of the actual and

theoretical curves show clearly that the nozzle-Venturi valve will

pass significantly more gas at lower casing pressures. For

example, at a casing pressure of 40 bar, a square edged orifice

would pass approximately 1300m3/d, and at the same casing

pressure, the nozzle-Venturi would pass 5200m~/d, The operat-

ing tubing pressure at the valves is very close to 10% less than

casing pressure. This indicates that the nozzle-Venturi orifice is

operating in the region that is right at the beginning of the critical

flow region. This region shows the greatest difference in flow

rate between the square edged orifice and nozzle-Venturi orifice

as can be seen in the difference between points A and B in Figure

2.

Test results confkrrted that the prediction program for sizing

of the nozzle-Venturi for the given well conditions is accurate

and that the nozzle-Venturi valve was able (o provide economic

advantage by reducing the casing pressure and quantity of lift gas

required to provide production comparable to that produced with

a square edge orifice valve of the same size.

Nozzle-Venturi Valve Advantages

The main advantage of the nozzle-Venturi valve over other gas

lift valves (including the orifice valve) is that critical flow can be

achieved with a production pressure that is only 6?10-10% lower

than the upstream pressure whereas standard valves require a

40% differential, Other advantages include the following:

1.The gas lift casing flow instability can be eliminated since the

nozzle-Venturi valve can always operate in the critical flow

regime.

2. The flow rate through the nozzle-Venturi valve will be higher

than the flow rate through the standard valve, as shown by points

A and B in Figure 2. Therefore, in high-rate installations, the

number of required valves per well can be reduced.

3. The injection flow rate through the gas lift valve can be

controlled at the wellhead by regulating the injection pressure,

preferably by a pressure controller.

4. In dual completions, the gas injection rate into each of the

production strings can be controlled, preventing gas robbing, a

common occurrence in duals, by the more productive string. R

5. In a gas lift field, the nozzle-Venturi valve can reduce the

tubing head pressure fluctuations and eliminate the casing head

pressure fluctuations, thus facilitating gas allocation and field

optimization.

6. The dimensions of the nozzle-Venturi valve allow it to be

used in any standard side pocket mandrel, and standard latches

can be used.

It should be noted that the case histories have only been able

to verify the production capabilities of the valves in short term

trials. The development of the nozzle-Venturi has been so recent

that there has not been sufficient time to compile data concerning

long term cost advantages and/or increased production that can

be attributed to usage of the new valve.

Conclusions

The nozzle-Venturi valve will eliminate casing heading caused

by fluctuations in the gas injection rate. It will inject at a

constant rate with a constant pressure no matter what the tubing

pressure is as long as the tubing pressure is 107. less than the

casing pressure at the point of gas injection, This eliminates one

of [he many variables contributing to tubing heading. In dual

applications, a nozzle-Venturi in each string at the injection point

will allow a constant and predictable flow rate into each well,

given a constant casing pressure. If one well has a history of

fluctuating tubing pressure, the casing pressure will fluctuate and

will affect the injection rate of the other well when square-edged

orifices are used. If a nozzle-Venturi is used, a fluctuating tubing

pressure in one string will not cause the casing pressure to

fluctuate. Thus, the second string will be unaffected. The same

concept can be used

when

multiple wells use the same injection

pressure source. A nozzle-Venturi in each well will ensure that

the injection flow rates will be constant as long as the source

pressure remains constant and the tubing pressure is 10% to

100% less than the casing pressure. A computer throat-diameter

sizing program has been developed to facilitate prediction of gas

injection rates.

Acknowledgments

The authors wish to thank Chevron and Halliburton Energy

Services for their support in advancing this technology and for

permission to produce this paper.

References

1.

2.

3.

4.

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API

Drilling and Production Practice 1954.

Grupping, A.W,, Luca, C.W.F., Vermulen, F.D.: “Continuous

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Grupping, A.W., Luca, C.W.F., Vermulen, F.D.: “Continuous

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Everitt, T.A.: “Gas-Lift Optimicaiton in a Large, Mature GOM

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6 T. TOKAR,Z. SCHMIDT,and C. TUCKNESS

SPE 36597

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Blick,E.F.,Enga, P.N.,Lhr, P.C.: “StabilityAalysisofFlowing

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1988,1452-56.

Alhanati, F.J.S., Schmidt, Z, Doty, D.R.: “Continuous Gas-Lift

Instability: Diagnosis, Criteria, and Solutions,” paper SPE 26554,

presented at the SPE 68th Annual Technical Conference and

Exhibition, Houston, TX, 3-6 October 1993.

Clegg,

J.D.:

“DiscussionofEconomicApproach to Oil Production

andGas Allocation in Continuous Gas Lift,” .lPT February 1982,

301-302.

Mach, J.M., Proano, E.A., Mukherjee, H., Brown, K.E.: ’ANew

Concept In Continuous-Flow Gas Lift Design;’ paper SPE 8026,J

SPE

Dec.’83, 885-890.

DeMoss, E., Gas Ll~tManual Teledyne Merla, Garland, Texas.

Brown, K.E.: “The Technology of Artificial Lift Methods,”

Petroleum Publishing Company, Tulsa Oklahoma.

S1

Metric Conversion Factors

bar

X

1.0* E+05=Pa

in. x2.54* E+OO=cm

psi x 6.894757 E+OO=kPa

bbl X 1.589873 E+03=mz

*Conversion factor is exact

Table 1. Input Variables

BOPD

BLPD BS&W

ProducedGOR

Injected SCF/D

Long String

I

1,038

I

1,298

I

20%

I

559

I

773

WHP (

Oii Gravity

Reservoir Pres- Reservoir Tempera-

PSiG)

(:S~G)

(APi)

sure (PSIG) ture (F)

Short String

170 994 18

1,780 160

Long String

210 994 28

1,400

180

240


7/14

Inlet Ports

Converging Section

Throat (Orifice)

Diverging Section

Packing

Check Valve

Outlet Ports

Figure 1

The Nozzle-Venturi Valve

241


8/14

Critical Flow

Conventional

New Nozzle-

Venturi Valve

I

Critkel Flow

Subcritical I

Gas

: Flow

Injection

I

Rate

:

I

I

I

I

Production Preaaure ~

Figure 2

Flow Performance of a Conventional OrificeValve Compared to a Nozzle-VenturiValve

quare-Edge Orifice

‘Nozzle-Venturi Circular Arc Venturi)

1~”

—----,

900

I

~utl

\wVen

I

*O*

Square-Edge Orifice

----- -- 1-- ----- ----- ----- ----- ----- ----- ---~

Distance

Figure 3

Pressure Profiles

for Square-Edge

Orifice and Nozzle-Venturi Valves

242


9/14

400

350

300

e

~ 250

5 ‘0

( 150

u.

100

50

0

.

0

m“

400

600

600

1000

12(M)

1400

i600

IICWMT- P~

(w

Figure 4

Nozzle-Venturi.1 25 Orifice Flow Curve Comparison

26m

500

n

“

o

200

400

600

600

mm

I

zm

1400

16m

Tubing Pressure

Figure 5

Nozzle-Venturi .324 Orifice Flow Curve Comparison

60W

.*

a

2om

n

o

200

400

500

600

lom

12m

1400

16~

T@ng Presewe (psi)

Figure 6

Nozzle-Venturi .500 Orifice Flow Curve Comparison

243


10/14

2,000

1,8U0

1,6Q0

$1,400

1,200

1,000

WI

Live

~

I

...

...

...

...

...

...

...

...

Well E-16 Completion Schematic

..-.....--”” -

..&-

------

-----

*----

..-

.. -

...

~ A*

.,

/’

,.’

.’

.

.

.

.

,

*

.’

.

.

.

/

A-

/

0

200

400 400

MO

1 1 2

1,400

Injoctlon QU Volunn (MWD)

Figure 8

Predicted ProductIon Rates

244


11/14

17000da

o

6020

\.

“,,

i.

‘,,

4

‘ ,

&

A

.,.

k

‘,

i

\

I

I

I

\

I

\

I

I

\

\

~.a

I

I

Unlmdng’”..

I

Vdw

4

I

‘i

I

I

o

zm 4m 600 000 1000 1200

1400 fn Imo 2000

RNmnm (HG)

Figure 9

PredictedTubing Pressure with Nozzle-Venturi Gas Injection Rates

“’oo~

2,000

g

g

I

1,700

t

1

520 MO

7m

am Wo

Tubing Woauro Al m. Vdw @.SIG)

Figure 10

Surface Casing Pressure Required to

Open Gas Lift Valve in Second Mandrel

245


12/14

0

F

g

e

1

W

e

E

1

L

S

n

B

o

e

N

e

V

u

I

n

a

a

o

F

g

e

1

W

e

E

1

S

n

A

e

N

u

I

n

a

a

o


13/14

a

u

.

,

247


14/14

2,000 I

I

mm

1,000

1,200

1,400

1,600 1,64)0

Sutface Casing Pressure (PSIG)

Figure 15

Nozzie-Venturi Performance Based on Surface Casing Pressure

8

/“

/-

60

./ /..

./

5

~

t

a

4

~ 30 -

i

i.-

..- ,

,..

i

I

I

i

I

20

..”

I

-..

i

I

I

I

10

i = ” ’ ”

I

I

. “O””.” I ,wwd)

I

15200 (mVd)

-.*

,.

0 ‘

1

I

1 1 I I 1

I t

2,000

2000 2000 6000 Woo

6000 7000

8000 6000 10000

Gas Injoc tlon Rat . (ma id )

Figure 16

Nozzle-Venturi

Flow Performance Comparison to Squar-Edged

Orifice Performance

Actual andTheoreticai Curves

248

new gas lift valve design

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