bombeo neumatico continuo spe74414ms
DESCRIPTION
In the southern region of Mexico, there are very deep natural fractured reservoirs, which after its first stages of exploitation, they need some kind of artificial lift systems.The application of artificial lift systems is very difficult and expensive in these type of reservoirs. ContinuousGas lift represents a good option to be considered as an artificial lift method due to both relatively low cost and easy application.TRANSCRIPT
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Copyright 2002, Society of Petroleum Engineers Inc. This paper was prepared for presentation at the SPE International Petroleum Conference and Exhibition in Mexico held in Villahermosa, Mexico, 1012 February 2002. This paper was selected for presentation by an SPE Program Committee following review of information contained in an abstract submitted by the author(s). Contents of the paper, as presented, have not been reviewed by the Society of Petroleum Engineers and are subject to correction by the author(s). The material, as presented, does not necessarily reflect any position of the Society of Petroleum Engineers, its officers, or members. Papers presented at SPE meetings are subject to publication review by Editorial Committees of the Society of Petroleum Engineers. Electronic reproduction, distribution, or storage of any part of this paper for commercial purposes without the written consent of the Society of Petroleum Engineers is prohibited. Permission to reproduce in print is restricted to an abstract of not more than 300 words; illustrations may not be copied. The abstract must contain conspicuous acknowledgment of where and by whom the paper was presented. Write Librarian, SPE, P.O. Box 833836, Richardson, TX 75083-3836, U.S.A., fax 01-972-952-9435.
ABSTRACT The Mora Field is located 60 kilometers from
Villahermosa Tabasco in the southern region of Mexico.
A project of self-sufficient system for continuous gas lift
in a very harmful sour gas environment was performed.
The gas lift infrastructure is not going to be installed in a
short time due to many problems such as logistic issues.
The self-sufficient system separates the gas from the
liquid. Then, it is compressed and injected into the well,
similar to an artificial gas lift. This system uses special
coiled tubing for sour gas handling. In addition, a
continuous chemical inhibitor is injected to protect both
the tubing and the coiled tubing from either cracking
failure or corrosion, (because the H2S and CO2 content
in the mixture is too high).
The goal of this work is twofold: (1) present a facility
design and (2) present a process to choose the
equipment for this particular application based on the
well productivity. Because the probability of both
cracking and corrosion is high, sizing the equipment and
selecting the appropriate material are special issues for
the success of this application.
Based on this pilot test, a major project is being
implemented to install this system in those fields with
high content of sour gas and without gas lift
infrastructure.
INTRODUCTION
In the southern region of Mexico, there are very deep
natural fractured reservoirs, which after its first stages of
exploitation, they need some kind of artificial lift systems.
The application of artificial lift systems is very difficult
and expensive in these type of reservoirs. Continuous
Gas lift represents a good option to be considered as an
artificial lift method due to both relatively low cost and
easy application.
Mora field produces from the lower cretaceous with
depths around 5500 meters. Currently, the pressure of
the reservoir is below the bubble pressure. A secondary
gas cap is being formed in the top of the reservoir. Both
the reservoir pressure and low gas-oil ratio had caused
the shutting of several wells. Therefore, it is necessary to
SPE 74414
Self-Sufficient System For Continuous Gas Lift In A Very Harmful Sour Gas Environment
Miguel A. Lozada Aguilar, Hiplito Peregrino Ramos, Ariel ramos Inestrosa, Ramiro Acero Hernndez, SPE, Pemex, PEP
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2 M. LOZADA AGUILAR, H. RAMOS, A. INESTROSA, AND R. HERNNDEZ SPE 74414
implement some kind of artificial lift systems to maintain
the oil production.
Gas lift is the most used artificial lift system in Mexico.
Almost 50% of the total production comes from fields
equipped with artificial gas lift. Because of logistic
issues, it has not been possible to install a gas lift
network in Mora field. To implement an artificial gas lift,
two options were taken into account: first, use nitrogen
as a gas lift source, but due to corrosion problems and
high power demand, this option was eliminated. Second,
use a self-sufficient gas lift system in the well location,
suitable for overcoming the corrosion and cracking
problems due to the sour gas.
Self-sufficient gas lift system has been applied for a long
time. To the best of our knowledge, there is no work
reported about corrosion and cracking problems in gas
lift. By using both coiled tubing for injecting the sour gas
and corrosion inhibitors, this paper tries to show a new
application for facing such problems. (See figure 1). SYSTEM DESCRIPTION
The proposed self-sufficient gas lift system separates
the gas from the liquid. Then It is compressed, dried and
injected through the coiled tubing mixed with the
corrosion inhibitors. The oil is lifted through the annulus
between tubing and coiled tubing. (See figure 2). Separator This equipment separates the gas from the mixture of
liquid-gas, which comes from the well. Then, the liquid is
sent through the flow line and the gas stream is sent to
the compressor suction.
Scrubber To dry the gas, a scrubber is used. This device catches
the liquid from the gas stream and then it is sent to the
compressor suction.
Control equipment This equipment includes the valves and the control
devices to keep the compressor, separator and scrubber
operating properly. It also helps to regulate the operation
pressure and the amount of gas to be compressed.
Compressor This equipment compresses the sour gas. Normally
these units have scrubbers and coolers integrated for
each compressor stage.
Corrosion inhibitors equipment This equipment injects the corrosion inhibitor into the
gas stream. The equipment is composed by a pneumatic
pump, a corrosion inhibitor deposit and a chemical
inhibitor. The way the chemical inhibitor protects the
tubing and coiled tubing from the sour gas attack, is by
covering the internal tubing walls through a fine cap.
Coiled tubing and hanger Coiled tubing is the means by which the sour gas
together with the chemical inhibitor is injected for gas lift
purposes. Coiled tubing hanger has the function of
hanging the coiled tubing from the surface and it also
provides the seal between tubing and coiled tubing.
CHALLENGES
The main challenge to be achieved is to maintain the
equipment integrity. It is important to mention that the
gas stream has 4% mole of H2S and 1.44% mole of
CO2, which combined with water could be a very corrosive mixture. In addition, the high content of H2S
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SPE 74414 SELF-SUFFICIENT SYSTEM FOR CONTINUOUS GAS LIFT IN A VERY HARMFUL SOUR GAS ENVIRONMENT 3
combined with the high pressure can cause cracking
phenomenon.
Corrosion is a phenomenon of oxidation when water and
steel are combined with either H2S or CO2. It is greatly
accelerated as the temperature increases. All of those
conditions are present in this particular case
Cracking phenomenon takes place where the steel
suffers tension and the gas contents H2S at certain
pressure. The root of this phenomenon comes from the
hydrogen ionization, which penetrates the steel and
reacts with carbonate to liberate methane, causing the
steel to be more ductile and therefore more likely to be
cracked. Figure 3 shows that with 4% mol of H2S into the gas stream, and 2000 psig of surface pressure, cracking
phenomenon will take place.
To avoid all of these risks, the following measures were
considered:
- Compressor to be used in this application should be
built for sour gas handling.
- A Coiled tubing to inject the sour gas into the well ,
should be used as a first step for avoiding the
corrosion and cracking problems.
- A chemical corrosion inhibitor should be injected into
the gas stream through the coiled tubing, as a
second step for avoiding the corrosion and cracking
problems.
Another challenge to be achieved is to make the facility
safety for a normal and continuous operation. Regarding
this point, the following measures were considered:
- Safety valves operated with differential pressure
should be installed in order to stop the system
operation when an unexpected leak comes up.
- Automatic stop for electrical motor should be
provided for protecting the mechanical components
of the compressor.
- Sensor for H2S should be provided in order to stop
the motor when some gas leak comes up.
- The facility should be supervised by specialists on
safety measures.
EQUIPMENT SIZING
The equipment sizing process was done based on the
well productivity and the flow properties. The following
procedure was performed to reach this goal:
Calculation procedure: 1. Choose a reservoir model that matches the historic
reservoir behavior.
2. Choose a correlation for vertical flow that matches
with measured data.
3. Choose a correlation for horizontal flow, which gives a
good match with the observed data.
4. Determine the optimum gas injection rate to be
injected, by using a commercial software for multiphase
flow.
5. Determine the flowing gradient all along the tubing, by
using the data obtained in the previous step.
6. Determine the available gas pressure at different
depths by using the Culender and Smith procedure. It is
necessary to do a sensitivity analysis with several coiled
tubing sizes for determining several gradient curves.
7. Determine the surface injection pressure needed for
injecting the sour gas at certain depths. This step can be
done by comparing the flowing gradient obtained in the
step No.5, and the available pressure obtained in the
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4 M. LOZADA AGUILAR, H. RAMOS, A. INESTROSA, AND R. HERNNDEZ SPE 74414
step No.6. The surface injection pressure must be read
at the surface from the appropriate gradient curve.
8.- Determine the potency requirements With the
optimum gas injection rate obtained in the step 3, and
the surface injection pressure obtained in the step 7.
9.- Select the engine potency required for this particular
application, giving a security margin.
Comments: - Vogel correlation was used as a reservoir model.
Hagedorn and Brown correlation was used for
vertical flow correlation. Begs and Brill was used for
horizontal flow correlation.
- According to figure 4, the optimum gas injection rate for this well is 1 MMSCFD, and It is possible to
produce 200 STBD more by using 1 instead of 1
coiled tubing size.
- In figure 5 we can see, that as the injection point gets deeper, the production rate increases, being
possible to produce 150 stbpd more, by injecting gas
at 4500 meters instead of 4000 meters. In order to
take the decision where the injection point will be
located, it is necessary to determine the potency
requirements for each depth.
- In the figure 6 we can observe that injecting gas at 4000 meters, it is necessary to have 1700 psig and
1850 psig of surface injection pressure, by using 1
and 1 coiled tubing size respectively. In the
same figure, we can observe that if we decided to
inject gas at 4500 meters, 1850 psig and 2050 psig
of surface injection pressure is required, by using 1
and 1 coiled tubing sizes respectively.
- Finally, from figure 7, we can observe that as the injection point gets deeper, the potency
requirements increases. Taking the desition to inject
gas at 4500 meters, it is required 8 HP more than if
we inject gas at 4000 meters. From the same figure,
we observe that using 1 instead of 1 coiled
tubing size, we required 8 HP more of potency.
Based on previous calculations, 200 HP motor was
requested for this operation, giving a good security
margin.
It was not possible to get a 1 coiled tubing size.
Therefore a 1 coiled tubing size was installed. It was
also decided that during the first test stage, the injection
point would be set at 4000 meters. After the first coiled
tubing revision, the injection point would be set at 4500
meters, using a 1 coiled tubing size. EQUIPMENT DESIGN Coiled tubing Coiled tubing selection is a very important issue for
keeping the system safety. As we mentioned before,
either corrosion or cracking problems inside the tubing
are likely to be happened. The coiled tubing selected for
this particular application is made of an special steel
alloy, which resists the sour gas environment and delays
corrosion problems. The steel alloy for this coiled tubing
is as follows:
Component Composition (weight %) C 10-14
Mn 10-90
P 2.5 (maximum)
S 0.5 (maximum)
Si 30-50
Cr 50-70
Cu 25 (maximum)
Ni 20 (maximum)
Mo 21 (maximum)
Compressor.- The compressor selected for this application, is a
reciprocate type with double effect . This compressor
has internal components to operate with sour gas, and it
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SPE 74414 SELF-SUFFICIENT SYSTEM FOR CONTINUOUS GAS LIFT IN A VERY HARMFUL SOUR GAS ENVIRONMENT 5
is moved with a 200 HP electrical motor. It also has two
stages, because the compression ratio is 13.33 for this
particular case. Suction pressure is ranged between 150
to 250 psig, as long as the discharge pressure is ranged
between 1600 to 2000 psig. Gas to be comprised has
0.8 SG with 4% mol of H2S, and 1.44% mol of CO2 .
Separator Separator to be used for this application handles sour
gas. The separator is 56 of diameter and 20 feet length.
This separator is oversized, because it was decided to
use an available one.
Corrosion inhibitor system This system is designed for handling 5000 PSIG of
pressure and 200 liters per day of pumping capacity.
Mexican Petroleum Institute determined that the
optimum inhibitor injection rate required was between 20
to 30 liters per day. During normal operation this
injection rate will be adjusted according to the needs. START UP OPERATION The operation started in March of this year. Although it
was necessary to make some modifications over the
facilities, it was considered a successful one. The way of
how the system was installed is depicted in figure 8.
Troublesome during the start up stage The main problems during this stage are as follows:
- Well flow instability was presented during pilot test,
mainly because it was on sub-sonic regime and
also due to the flow patterns. Both conditions are
related to the well productivity index and the well
geometry.
- The system control nature of the separator is the
main factor which makes the system to be unstable.
As we said before, this well flows on sub-sonic
regime, and the separator is very close to the tubing
head.
- The well instability grade depends on the gas
injection rate and on the tubing head choke size. For
this particular application, it was necessary to
produce the well with 5/8 tubing head choke size,
and by injecting 1 mmstcf/d, in order to keep the well
flow stable.
- It is very important that the compressor operation
must be as stable as possible, because during
unstable conditions the compressor components
degrade faster. Indeed, we had a lot of problems
because the suction valves degraded very rapidly.
Solutions Some modifications were made to the initial project to
make it more efficient, as we describe as follows:
- In order to keep the compressor pressure stable, it
was proposed to install two additional scrubbers
after the separator, and to change the 2 gas line
which connects the separator with the compressor,
for one of 6.
- Change the relay valve from the second
compressor stage to the first compressor stage.
- Install a device in the separator control, in order to
make the communication between the level control
and the separation pressure faster.
The diagram after the modification is depicted in
figure 9.
RESULTS
Before the modifications were done, this system had an
instability problem, therefore, the compressor suction
valves needed to be changed very often. After this
system was modified, it has been working in a
continuous way up to now, having shutting periods due
to the electrical power failures in the area.
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6 M. LOZADA AGUILAR, H. RAMOS, A. INESTROSA, AND R. HERNNDEZ SPE 74414
In order to start up the system after the shutting periods,
it was necessary to use nitrogen, increasing the
operation expenditures; thereby, it was necessary to use
the free gas storage into the casing for this purpose,
giving an excellent result. From July on, we have not
used any nitrogen at all for starting up the system. It is
important to mention that natural separation gas is taking
place into the well, as the tubing is communicated with
the casing.
It was not possible to produce the designed oil rate,
because the unstable flow condition did not allow us to
increase the tubing head choke size. The designed oil
rate is 1000 STBD, and the well is producing only 800
STBD.
ENHANCED SELF-SUFFICIENT SYSTEM FOR CONTINUED GAS LIFT.
In the following section, we describe some
recommendations to enhance the self-sufficient system
for continuous gas lift:
- Sour gas injection should be done, by using a 1
coiled tubing size, and by injecting corrosion inhibitor
into the gas stream.
- For compressors moved with electrical motor, it is
recommended to use a variable speed driver, in
order to make the gas injection adjustment easier,
which is a very important issue in wells with unstable
flow.
- It is also important for this kind of wells, to have a
scrubber in the separator discharge, and to have a
6 or 8 gas line between the scrubber and the
compressor suction, in order to avoid the unstable
flow condition.
- On wells which are flowing on subsonic regime, it is
also important to have a variable tubing head choke,
in order to make easier the choke size adjustment
during the normal operation, because this is an
important parameter for getting the well stabled.
ECONOMICAL ASSESSMENT. This project has excellent economical indicators,
because the initial investment is $500, 000 dollars, and
the oil production increment in 800 STBD. In figure 10, we can observe the basis for this analysis and the
indicators gotten from them. The net present value in ten
years will be $ 15 MM dollars, with an investment
efficiency of 30. It seems that those indicators are out of
range, but the real point is that the investment is low,
and the oil production increase is high.
CONCLUSIONS.
This work centers on the design of an artificial gas lift
with sour gas. The main findings of this work are:
1. The self-sufficient system for continuous gas lift is
totally feasible in the way that it is proposed.
2. This system is an excellent option for those wells in
which gas lift is the best option for artificial lift systems,
and where there is not available infrastructure. In the
Bellota-Chinchorro Asset, it has been possible to
produce at least 7000 STBD
3. By using the coiled tubing and the chemical corrosion
inhibitors, cracking and corrosion will be in high
proportion avoided.
4. This system involves many disciplines, therefore, it is
very important to form a multidisciplinary group to be
successful.
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SPE 74414 SELF-SUFFICIENT SYSTEM FOR CONTINUOUS GAS LIFT IN A VERY HARMFUL SOUR GAS ENVIRONMENT 7
5. This project has excellent economical indicators,
having a net present value of $ 15 mm dollars and an
investment efficiency of 30, over ten years of period
analysis.
6. Currently, a major project with seven wells is taking
place, previous to the installation of the gas lift network.
ACKNOWLEDGMENTS
- This project would not have been possible without
the support from our authorities.
- We thank Ing. Jorge Carranza Becerra for giving us
some excellent ideas for this project.
- We thank P.H. Victor Hugo Arana for helping us on
this project.
REFERENCES.
Bombeo neumtico autoabastecido.-- Jos Angel Gomez Cabrera..- Revista internacional del petrleo
1998.
The Technology of Artificial Methods -volume 2a- Kermit E. Brown.
Temas selectos sobre bombeo neumtico continuo- Colegio de Ingenieros Petroleros de Mxico.
Optimizing Production With Artificial Lift Systems, july 1989, petroleum Engineer, L. Douglas Patton,
Aurora, Colo.
Recommendations and Comparisons for Selecting
Artificial-Lift Methods, SPE, J.D. Ciegg, S.M.
Bucaram, N.W. Heln Jr.
Factibilidad de sistemas artificiales de produccin en el campo Crdenas, Instituto Mexicano del Petrleo,
1985, Ing. Horacio Ziga Puente.
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8 M. LOZADA AGUILAR, H. RAMOS, A. INESTROSA, AND R. HERNNDEZ SPE 74414
Figure 1: Well characteristics in Mora field
Figure 2: System diagram.
10 "
7 5/8"
3544 m
5075 m
LINER 5" 4286 m
4270 m
5472 m5"5433.50 m
PAY ZONE. 5285-5327 m
24
16" 1002 m
50 m
PAKER 7 5/8
3 1/2
Pws = 200 kg/cm
Tf = 141C
CO2 = 2-3 % mol
H2S = 4-7 % mol
Water cut = 0%
API = 37
= 0.74 g/ccg
10 "
7 5/8"
3544 m
5075 m
LINER 5" 4286 m
4270 m
5472 m5"5433.50 m
PAY ZONE. 5285-5327 m
24
16" 1002 m
50 m
PAKER 7 5/8
3 1/2
10 "
7 5/8"
3544 m
5075 m
LINER 5" 4286 m
4270 m
5472 m5"5433.50 m
PAY ZONE. 5285-5327 m
24
16" 1002 m
50 m
PAKER 7 5/8
3 1/2
Pws = 200 kg/cm
Tf = 141C
CO2 = 2-3 % mol
H2S = 4-7 % mol
Water cut = 0%
API = 37
= 0.74 g/ccg
Pws = 200 kg/cm
Tf = 141C
CO2 = 2-3 % mol
H2S = 4-7 % mol
Water cut = 0%
API = 37
= 0.74 g/ccg
8 F L O W L I N E
G A S I N J E C T I O N L I N E
L G L C
L G L CR
C
L Q U I D
S8 "
T U B I N G 3 1 / 2 C O I L E D
T U B I N G 1 1 / 2
s s v
I N H I B I T O R C O R R O S I O N
P A Y Z O N E
8 F L O W L I N E
G A S I N J E C T I O N L I N E
L G L C
L G L CR
C
L Q U I D
S8 "
T U B I N G 3 1 / 2 C O I L E D
T U B I N G 1 1 / 2
s s v
I N H I B I T O R C O R R O S I O N
P A Y Z O N E
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SPE 74414 SELF-SUFFICIENT SYSTEM FOR CONTINUOUS GAS LIFT IN A VERY HARMFUL SOUR GAS ENVIRONMENT 9
Figure 3: Cracking diagram.
Figure 4: Optimum gas injection rate .
PPM H2S INTO THE GAS
0.0001 0.001 0.01 0.1 1 10
% MOL H2S
10
100
1,000
10,0001 10 100 1,000 10,000 100,000
REGIN DE AGRIETAMIENTO DEL MATERIAL POR CORROSIN BAJO
ESFUERZO EN PRESENCIA DESULFHIDRICO
REGIN SIN AGRIETAMIENTO DEL MATERIAL
PPM H2S
0.0001 0.001 0.01 0.1 1 10
% MOL H2S
10
100
1,000
10,0001 10 100 1,000 10,000 100,000
REGIN DE AGRIETAMIENTO DEL MATERIAL POR CORROSIN BAJO
ESFUERZO EN PRESENCIA DESULFHIDRICO
REGIN SIN AGRIETAMIENTO DEL MATERIAL
TO
TA
L P
RE
SSU
RE
(PSI
A)
PPM H2S
0.0001 0.001 0.01 0.1 1 10
% MOL H2S
10
100
1,000
10,0001 10 100 1,000 10,000 100,000
CRACKING REGION
REGIN SIN AGRIETAMIENTO DEL MATERIAL
NO CRACKING REGION
OF
OF
INTO THE GAS
PPM H2S INTO THE GAS
0.0001 0.001 0.01 0.1 1 10
% MOL H2S
10
100
1,000
10,0001 10 100 1,000 10,000 100,000
REGIN DE AGRIETAMIENTO DEL MATERIAL POR CORROSIN BAJO
ESFUERZO EN PRESENCIA DESULFHIDRICO
REGIN SIN AGRIETAMIENTO DEL MATERIAL
PPM H2S INTO THE GAS
0.0001 0.001 0.01 0.1 1 10
% MOL H2S
10
100
1,000
10,0001 10 100 1,000 10,000 100,000
REGIN DE AGRIETAMIENTO DEL MATERIAL POR CORROSIN BAJO
ESFUERZO EN PRESENCIA DESULFHIDRICO
REGIN SIN AGRIETAMIENTO DEL MATERIAL
REGIN SIN AGRIETAMIENTO DEL MATERIAL
PPM H2S
0.0001 0.001 0.01 0.1 1 10
% MOL H2S
10
100
1,000
10,0001 10 100 1,000 10,000 100,000
REGIN DE AGRIETAMIENTO DEL MATERIAL POR CORROSIN BAJO
ESFUERZO EN PRESENCIA DESULFHIDRICO
REGIN SIN AGRIETAMIENTO DEL MATERIAL
REGIN SIN AGRIETAMIENTO DEL MATERIAL
TO
TA
L P
RE
SSU
RE
(PSI
A)
PPM H2S
0.0001 0.001 0.01 0.1 1 10
% MOL H2S
10
100
1,000
10,0001 10 100 1,000 10,000 100,000
CRACKING REGION
REGIN SIN AGRIETAMIENTO DEL MATERIAL
NO CRACKING REGION
0.0001 0.001 0.01 0.1 1 10
% MOL H2S
10
100
1,000
10,0001 10 100 1,000 10,000 100,000
CRACKING REGION
REGIN SIN AGRIETAMIENTO DEL MATERIAL
NO CRACKING REGIONREGIN SIN AGRIETAMIENTO DEL MATERIAL
NO CRACKING REGION
OF
OF
INTO THE GAS
0
200
400
600
800
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0 0.5 1 1.5 2 2.5
Gas injection rate (mmstcfd)
1 C.T.1 C.T.
0
200
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Prod
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Gas injection rate (mmstcfd)
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)
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10 M. LOZADA AGUILAR, H. RAMOS, A. INESTROSA, AND R. HERNNDEZ SPE 74414
Figure 5: Production Vs depth sensitivity.
Figure 6: Surface injection pressure requirements
-6000
-5000
-4000
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-2000
-1000
01000 1250 1500 1750 2000 2250 2500 2750 3000
Pressure(psig)
Dept
h(m
eter
s)
CT- 1 1/4"-1800 PSI
CT- 1 1/4"-1900 PSI
CT- 1 1/4"-2000 PSI
CT- 1 1/2"-1600 PSI
CT- 1 1/2"-1700 PSI
CT- 1 1/2"-1800 PSI
Well gradient
1 C.T. 1 C.T.
0
400
800
1200
1600
3000 3500 4000 4500 5000
Depth ( meters )
Prod
uctio
n ra
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SPE 74414 SELF-SUFFICIENT SYSTEM FOR CONTINUOUS GAS LIFT IN A VERY HARMFUL SOUR GAS ENVIRONMENT 11
Figure 7: Potency requirements
Figure 8: System diagram before the modification.
162164166168170172
174176178180182
3000 3500 4000 4500 5000
HP
CT-1
162164166168170172
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3000 3500 4000 4500 5000
GAS INJECTION DEPTH (METERS)
HP CT- 1
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3000 3500 4000 4500 5000
HP
CT-1
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3000 3500 4000 4500 5000
GAS INJECTION DEPTH (METERS)
HP CT- 1
S .H .
C
o
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N 2
S .H .
C
o
NE
N 2
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12 M. LOZADA AGUILAR, H. RAMOS, A. INESTROSA, AND R. HERNNDEZ SPE 74414
Figure 9: System diagram after the modification.
Figure 10: Economical assessment.
-2000000
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Analysis period (years)
N.P
.V. (
mm
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lars
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S.H.
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RECT.1