Bombeo Neumatico Continuo SPE74414MS

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

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

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


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


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.


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.


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.


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


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




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


NO CRACKING REGION

OF

OF

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





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





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





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


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


NO CRACKING REGIONREGIN SIN AGRIETAMIENTO DEL MATERIAL

NO CRACKING REGION

OF

OF

INTO THE GAS

0

200

400

600

800

1000

1200

1400

0 0.5 1 1.5 2 2.5

Gas injection rate (mmstcfd)

1 C.T.1 C.T.

0

200

400

600

800

1000

1200

1400

0 0.5 1 1.5 2 2.5

Prod

uctio

n ra

te (s

tbpd

)

0

200

400

600

800

1000

1200

1400

0 0.5 1 1.5 2 2.5

Gas injection rate (mmstcfd)

1 C.T.1 C.T.

0

200

400

600

800

1000

1200

1400

0 0.5 1 1.5 2 2.5

Prod

uctio

n ra

te (s

tbpd

)


Figure 5: Production Vs depth sensitivity.

Figure 6: Surface injection pressure requirements

-6000

-5000

-4000

-3000

-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

te

( stb

pd )

1 C.T.


Figure 7: Potency requirements

Figure 8: System diagram before the modification.

162164166168170172

174176178180182

3000 3500 4000 4500 5000

HP

CT-1

162164166168170172

174176178180182

3000 3500 4000 4500 5000

GAS INJECTION DEPTH (METERS)

HP CT- 1

162164166168170172

174176178180182

3000 3500 4000 4500 5000

HP

CT-1

162164166168170172

174176178180182

3000 3500 4000 4500 5000

GAS INJECTION DEPTH (METERS)

HP CT- 1

S .H .

C

o

NE

N 2

S .H .

C

o

NE

N 2


Figure 9: System diagram after the modification.

Figure 10: Economical assessment.

-2000000

0

2000000

4000000

6000000

8000000

10000000

12000000

14000000

16000000

0 2 4 6 8 10 12

Analysis period (years)

N.P

.V. (

mm

dol

lars

S.H.

C

NE

N2

RECT.2

RECT.1

S.H.

CC

NE

NE

N2

RECT.2

RECT.1

Bombeo Neumatico Continuo SPE74414MS

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