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Copyright 2001, Society of Petroleum Engineers Inc.

This paper was prepared for presentation at the SPE Latin American and Caribbean PetroleumEngineering Conference held in Buenos Aires, Argentina, 2528 March 2001.

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, aspresented, have not been reviewed by the Society of Petroleum Engineers and are subject tocorrection by the author(s). The material, as presented, does not necessarily reflect anyposition of the Society of Petroleum Engineers, its officers, or members. Papers presented atSPE 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 isprohibited. Permission to reproduce in print is restricted to an abstract of not more than 300words; illustrations may not be copied. The abstract must contain conspicuousacknowledgment 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.

AbstractThis paper describes the successful experience

obtained in using electro-submersible pumps (ESP) in the production of abrasive and corrosive fluids. The study covers60 wells operated by the Consorcio equiped with ESPs inOritupanoLeona field, States of Anzoategui and Monagas,East Venezuela.The influence of the reservoir on the pump run life isreviewed. Currently, 46% of the total oil is produced throughESPs, the first instaled in 1996. Most of the failures arerelated to sand production and corrosion. Since the start of this

program, pulling jobs due to ESPs failures have beensignificantly reduced, due to practices that increase the run lifeof the pumps, including:- a start-up procedure to reduce fines production- an exhaustive, teamwork based, study of the failures- the use of special abrasion / corrosion resistant materialsAll of these factors combined have allowed to optimize theapplication of ESPs in this field. Details of the variousmethodologies used to achieve the optimization of the ESPsystem in Oritupano and Leona fields are presented.

Introduction

The Oritupano-Leona block is located in East Venezuelaand covers part of the Anzoategui and Monagas States (Figure1). Within the block, Oritupano and Leona fields are located.The block was assigned by PDVSA (Venezuela State OilCompany) to the Consorcio Perez Companc-UPR-Corod in1994.In the two fields there are about 60 wells equipped with ESPs.The first pump was installed in November 1996. During 1997there were just a few installations with different results. At the

beginning of 1998 the Consorcio decided to start with ESPs

as a special project to develop different areas of the field wihigh IPRs. (Figure 2 and 3). In March 1998, the Consorc

began an Alliance with a pump supplier company.In Oritupano and Leona fields there are areas with mediumheavy crude in the upper Oficina Formation, and an extheavy crude at its bottom section. There are verticdirectional and horizontal wells producing with ESPs, somof them gravel packed.

ESPs application began with standard equipment of differerates. Due to the aggressiveness and corrosiveness of the flu produced, material specifications have been changed. Now th pumps are producing volumes up to 10.000 bfpd usivariable speed drivers (VSD) and plans have been made increase the flow rates in some areas of the field.

The Initial ProblemsAfter the first installations several problems arise:- High Sand Production- Corrosion- Scale

Various wells have sanded up after only a few days of being iservice, even though the startup rate was low. The sanding u

became critical initially because in one month there wereinterventions due to pump seizing. At that time, application of this production system in some zones of tfield was in doubt. The pumps lasted from 5 to 20 days unthey seized up.Corrosion due to CO 2 was found to be present in various wwhere we noted large holes in the housing of the motors anseals in many cases combined with erosion due to sa

production. In one of the wells, the corrosion failure w produced after 98 days of being in service.Most of the fluids produced in Oritupano-Leona have a scalintendency but just a small group of wells showed evidence calcium carbonate after being pulled out. Seizing up due scatook place in one of the wells after being in production days.

Techniques UsedBased on observations, efforts were made

concentrate on 4 different techniques for testing and problecontrol:

SPE 69434

ESP's Application in Oritupano-Leona block, East VenezuelaGumersindo Novillo, SPE, Perez Companc, and Herman Cedeo, W.G. ESP Inc.

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2 G NOVILLO, H CEDEO SP

Start-up ProcedureInitially, equipments were started up at operating

frequencies of 44 Hz., which caused the pump to prematurelyseize up in some wells due to sand problems. Because of this,it was decided to start the wells with a lower frequency. Insome wells, we also considered backpressure the wellheadand/or recirculating the production until the amount of sand

was stabilized. Modifications were made in the wellheadmanifolds that allowed to use chokes to control the

backpressure and recirculate the production if necessary.Results were excellent and it was possible to produce wellsthat before had seized up after only 5 days of service. So far,we have not had premature pump seizing due to sand in any of the new equipment that were installed. Currently, the changesin the wellhead manifold are a standard in any new ESPinstalled.

Frequency Increase ProcedureOnce the well has been producing with a lower

frequency, backpressured, and sand production has been

stabilized, frequencies is increased following a program up todesign flow rate. In some wells these increases were carriedout slower than in others when the amount of solids is greater than anticipated and/or the well conditions were different thanexpected. In all cases, frequency increments are made whilerecording all of the pertinent data, which are analyzed using a

pump design program that simulate well conditions.All of the information obtained is integrated into a procedure:Operating Procedure for Changing Frequency in ESP Wells,which is used by Production/Maintenance and EngineeringDepartments of the Consorcio and Pump Supplier. The mainobjective of this procedure is extend life of the equipment andat the same time to clarify, clasify and store all the informationrelated to ESPs handling.Results obtained to-date, after the implementation of the

procedures changes, have been very satisfactory even when insome cases, (due to the fact that some wells initially appear not to produce sand), we have been tempted to disregard the

procedure in order to produce faster.After learning some hard lessons, an agreement ahs beenachieved: to use the procedure with all the wells, in spite of the delays of production.

Failure AnalysisInitially the equipment pulled out the wells was sent

to the repair shop for teardown and inspection. The pumpsupplier followed this inspection with a written report. This

procedure was discarded and a new procedure was defined,Procedure for Failure Analysis which was applied to all theequipment removed from the wells. The procedure takes intoaccount the following information:

1 I nformation from Pull ing Job: This report includes all theinformation regarding the conditions under which theequipment failed, i.e. the ESP wellhead chart, etc. Specialconditions and evidence should also be included that indicate

presence of solids, carbonates, etc.

The responsibility of handling this information is on tProduction Engineer and the Application Engineer from t

pump supplier.

2 Operations Conditions of the ESP at the Well includes all the information regarding to the conditions which the well operated before the failure.

- production and water cut (%)- pump inlet pressures- wellhead and flowline pressure- representative amperage charts- characteristics of the fluids (CO 2 , H 2S, etc.)- amount and type of chemicals (date of injection)- number of interventions before

Again, responsibility of handling this information is Production Engineer and the Application Engineer from t

pump supplier.

3 Equi pment I nspection at the Shop: Information from 2 above is sent to the pump repair shop so that the personn

who will be carrying out the teardown is familiar in advanwith the pump conditions. For the teardown and inspectiothe pump supplier has a specialist in failure analyses who responsible for the work to be done.All the equipment taken from the well must be inspected bthe personnel of the Production Engineering Department of thConsorcio. Also operations personnel from the Consorcio tak

place of the teardown as part of their training program. some cases and depending of the equipment to be inspecte

personnel of the chemicals company also attend the teardownOnce the inspection at the pump repair shop is completedreport, Preliminary Report of Inspected Equipment, written and sent to the Consorcios personnel who assisted the inspection.

4 Post Teardown M eeti ng: Finally, a post teardown meeis held at the Consorcio offices where the PreliminaReport is discussed. Assistants are:

- Failure Analysis Engineer from Pump Supplier - Consorcio Production and Corrosion Engineers- Application Engineer from Pump Supplier -Field Supervisor from both Pump Supplier

Consorcio (as training)- Reservoir Engineers from Consorcio ( if required )

At this meeting, actions, which will extend the life of tequipment, are discussed and agreed upon. As a consequenof this type of work methodology, the equipment used ha

been optimized and the operation techniques have beclarified.

ChemicalsBased on the characteristics of the produced flui

the operational conditions of some wells (high flow and higintake pressures), and taking into account the observatiofrom the inspections at the repair shop, it was decided to bega program of corrosion inhibitor injection in most of the wel

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SPE 69434 ESP'S APPLICATION IN ORITUPANO: LEONA FIELD OF PEREZ COMPANC VENEZUELA OPERATION

equipped with ESP. In a few wells the injection of scaleinhibitors and friction reducer has been initiated.

Corrosion Inhibitor: Corrosion inhibitor is injected on acontinuous basis. The water soluble inhibitor, which is basedon quaternary amine chemistry, is injected via capillary tubing(where available) or directly down the casing reaching the

bottom because its heavier than the oil.Results obtained to date have been very encouraging andeffective in most of the wells. The following informationoutlines a few cases.

Well ORM-23Flow Rate 3500 bls / dWater Cut 85 %ESP running time before injection, 98 days.With chemical injection (via capillary) 435 days. Stdequipment in both cases. Pulling job cause, other thancorrosion.

Well ORM-89Flow Rate 5000 bls / dWater Cut 90 %ESP running time before injection, 142 days.With chemical injection (via Casing) 797 days. Std equipmentin both cases. Pulling job cause, other than corrosion.The equipment was pulled out with no failure, to produce ahigher rate with a larger pump. At that time, a corrosiondetection casing tool was run that showed corrosion on thecasing. Although the new equipment was monel coated, arecomendation was made to keep injecting inhibitor to protectthe casing and the tubing string.

Well ORM-70Flow Rate 3500 bls / dWater Cut 90 %ESP running time before injection, 235 days.With chemical injection (via capillary) 712 days (as of Oct 31,2000 still in production). Std equipment in both cases.

EQUIPMENTAs a result of this strict and methodic failure analysis, in someareas characteristics and materials in use were changed toimprove running life of the downhole equipment.Changes made to arrive at the equipment currently in use insome aggressive areas of the field include:

PumpsBeen sand and corrosion the most important problems,abrasion resistant pumps with mixed flow stages wereinstalled.Taking into account that there are areas of the field with water cut and productivity indexes increasing highly with time andthat the handling of production fines is a constant, we began toinstall pumps with compression stages. These pumps could beoperated over a broader range than the floating stage pumps

and it appears that they could also handle better the abrasivfluids.The operating range of this type of pump, in many casimproved the efficiency of lifting and reduced powrequirements, while working on the left side of the pumcurve in comparison to the floating stage pump . Oadditional advantage is standardization and a reduc

inventory. The whole range of wells production has becovered up to now with just three different pumps, TG 400TG 7000 and TE 11000. These compression pumps are beinused with good performance since the end of 1999 in heavy owells. The results are under evaluation..In some zones of the field where significant damage due abrasion has been found, a special coating in the impellers under evaluation.I depth analyzing the corrosion problems and considering nto increase the cost of the equipment, Monel coating is useadditionally stainless steel heads are being installed.

Gas Separators

Separators are abrasion resistant and additionally compression tubes have an internal coating of tungsten carbito minimize the damage. Gas separators are Monel coated, anstainless steel heads are being used.

SealsInitially simple seals were used, and contamination uccurrsooner than expected. Currently, we install seals with tandeconfiguration, 4 chambers with Aflas bags, abrasion resistasleeves and high load bearings. The seals are coated wMonel and stainless steel heads are being used.

MotorsHigh load, high temperature motors are applied. Monel coatand stainless steel heads are being used.

CableThe galvanized armor is Type I, most of the cables used havincorporated 3/8 capillary tubing for the injection chemical, with the end of the capillary 10 feet below tmotor.

RESULTS DISCUSSION (Figure 4)1Classification of Pulling Jobs: As a part of the analysithe pulling jobs were grouped according to the followingcriteria:

a ) Well Pr oblems Pulling Jobs due to:

- Type of fluid handled by the wells (corrosion, sanscale, etc.)

- Type of reservoir (high WOR, low productivity, etc)- Others (emulsions, change to a higher capacity pum

WO jobs, etc.) b ) Equipment Fail ure

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4 G NOVILLO, H CEDEO SP

When the failure produced is related to the equipment, itsassociated directly to the quality of the material, themanufacturing process or the installation procedure.

Following is a summary taking into account this classificationof pulling jobs.

First Stage November 1996 to December 97.4 pulling jobs for equipment failures and 7 for well problems.During the first stage, the well problems were: Sand (5 wells)and Carbonate (2 wells).

Second StageJanuary 1998 to December 1998.5 pulling jobs for equipment failures and 14 for well problems,

being the more relevant well problems: Sand (5 wells) andCorrosion (4 wells).

Third Stage

January 1999 to December 1999.3 pulling jobs for equipment failures and 12 for well problems, being the more relevant well problems: High Water Cut (5wells), Sand (4 wells) and Corrosion (1 well).

Fourth StageJanuary 2000 to October 20002 pulling jobs for equipment failures and 8 for well problems,

being the more relevant well problems: Sand (4 wells) andCorrosion (1 well).

Details on this can be seen in Figures 5, 6, and 7. Pulling Jobsin Fig.4, and 5 were extrapolated to Dec. 31, 2000. In Fig. 6and 7 actual Pulling Jobs, to October 31, 2000 can be seen

2-Rate of Pulling Jobs/Well-Year: One of the mainindicators that we are using to measure the efficiency of thesystem is the Pulling Jobs Index per Well per Year.

This Index reflects all the Pulling Jobs carried out on ESPduring the month (extrapolated for the year), whether the

pulling job is for failure of the downhole equipment or other causes. To calculate, the number of pulling jobs for the monthdivided by the total number of wells with active ESPs on thelast day of the month times 12.

Monthly Index = Pull. Jobs x month X 12 months

Total ESP Wells

This gives an average index from the start of the operationwith ESP, which can then be divided into 4 main stages:

From To PullJob/Well/

Year

Avg.ESRunnin

1 rst Stg. Nov 96 Dec 97 3.71 32nd Stg. Jan 98 Dec 98 1.03 183 thr Stg. Jan 99 Dec. 99 0.41 364 th Stg. Jan 00 Oct. 00 0.25 50

Taking into account the tendency of this Index (Figure 8), thReasons, and Number of Pulling Jobs the last fourth years wcan conclude and expect a continuous improvement at the rulife of the equipment.

The task of optimizing is not considered finished yet. Tobjective is to develop new options to optimize the runnintime and costs of the equipment. Currently the job is orienttowards coatings, and the power of the motors.

CONCLUSIONS The experience obtained, the techniques and

teamwork among the Consorcio, the pump and chemicals suppliers have shown that the application ESPs in the Oritupano-Leona field could be developwith success in spite of earlier difficulties.

Changes in materials in the downhole equipment wallow us to obtain longer duration in wells with corrosiand abrasive fluids.

The Pulling Jobs Index/Well/Year has been reduced fro3.71 to 0.25

From the analysis of the Reasons for Pulling a Pull ing Job Index in the ESPs, we can see and expecimportant and continuous improvement at the run life the equipment.

ACKNOWLEDGMENTSWe thank Consorcio Perez Companc-UPR-Corod, f

permission to publish this work. Thanks are also due to engineering staff of the Consorcio, Pump and Chemisupplier companies for their dedication and perseverance doing their jobs.

REFERENCES

[1] ESP Inc. Abrasion resistant guidelines. 1997

[2] Practical Oilfield Metallurgy and Corrosion Bruce Craig

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SPE 69434 ESP'S APPLICATION IN ORITUPANO: LEONA FIELD OF PEREZ COMPANC VENEZUELA OPERATION

Fig. 1.- ORITUPANO-LEONA OILFIELD.

SAN TOM

MONAGASMONAGASANZOTEGUIANZOTEGUI

BOLVARBOLVAR

SUCRESUCRE

GUARICOGUARICO

NVA. ESPARTANVA. ESPARTA

MIRANDAMIRANDA

CARACASCARACAS

DELTA AMACURODELTA AMACURO

EL TIGRE

ANZOTEGUIANZOTEGUI MONAGASMONAGAS

Fig. 2.- FIELD CONDITIONS.

QUANTITY FROM TO

# Of Wells 60

General DescriptionModeratly

consolidatedSandstone

PoorlyConsolidated

SandstoneCompletion No Gravel Pack Gravel Pack

Reserv. Permeability, darcy 0.5 1.5Reserv. Porosity 18 24Drive Mechanism Strong Water Drive

Well Production, bfpd 700 10000 API 10 23Setting Depth, ft 4500 5800Pump Intake Pressure, psi 400 1800Water Cut, % 20 96Casing, in. 5 1/2" 7 "Tubing, in. 2 7/8" 3 1/2"

H2S, ppm 1 600CO2, % 0.5 22Bht, F 170 220Sand, % Trace 3Scale Light ModerateGOR, scf / stb 50 1200SBHP, psi 1800 2500Bubble Point Pressure, psi 1200 2000Viscosity @ 180 F, cp 50 700ON / OFFSHORE On Shore

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6 G NOVILLO, H CEDEO SP

3

18

36

50

11

1915

12

0

10

20

30

40

50

60

1.997 1.998 1.999 2.000AVG. NUMBER OF ESPS PULLING JOBS

N

0

10

20

30

40

50

60

70

J a n - 9

7

M a r - 9 7

M a y - 9

7

J u l - 9 7

S e p - 9

7

N o v - 9

7

J a n - 9

8

M a r - 9 8

M a y - 9

8

J u l - 9 8

S e p - 9

8

N o v - 9

8

J a n - 9

9

M a r - 9 9

M a y - 9

9

J u l - 9 9

S e p - 9

9

N o v - 9

9

J a n - 0

0

M a r - 0 0

M a y - 0

0

J u l - 0 0

S e p - 0

0

(Actual Pulling Jobs, Fig 6 and 7, @ October 31, 2000)

7

14

12

10

4

5

32

0

2

4

6

8

10

12

14

16

1.997 1.998 1.999 2.000

WELL PROBLEMS FAILURES

0

2

4

6

8

10

12

14

16

1997 1998 1999 2000

SAND SCALE CORROSION

LOW PRODUCTIVITY EMULSION HIGHER VOLUME

HIGH WATER CUT

Fig. 3.- NUMBER OF ESPS RUNNING. Fig. 4.- ESPS RUNNING VS PULLING JOBS.(Pulling Jobs, Fig.4 and 5, extrapolated to Dec. 2001)

Fig. 5.- REASONS FOR PULLING JOBS.Fig. 6.- WELL PROBLEMS

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Fig. 7.- FAILURES

Fig. 8.- RATE OF PULLING JOBS/WELL/YEAR

0

1

2

3

4

5

6

1997 1998 1999 2000

MLC CABLE MOTOR

0.00

2.00

4.00

6.00

8.00

10.00

12.00

14.00

16.00

18.00

N o v - 9

6

J a n - 9

7

M a r - 9 7

M a y - 9

7

J u l - 9 7

S e p - 9

7

N o v - 9

7

J a n - 9

8

M a r - 9 8

M a y - 9

8

J u l - 9 8

S e p - 9

8

N o v - 9

8

J a n - 9

9

M a r - 9 9

M a y - 9

9

J u l - 9 9

S e p - 9

9

N o v - 9

9

J a n - 0

0

M a r - 0 0

M a y - 0

0

J u l - 0 0

S e p - 0

00.00

2.00

4.00

6.00

8.00

10.00

12.00

14.00

16.00

18.00

PULLING JOBS/WELL/YEAR

3,71

1,03 0,410,25