SPE-173699-MS

Integrated Methodology to Optimizes Production and Performance ofElectrosubmersible Pump System in Shushufindi Field

Gustavo Nuñez, Schlumberger; Juan Carlos Rodriguez, and Fabiola Carmona, SPE; Alfonso Esquivel,Schlumbegrer; Ana Larez, SPE; Jorge Dutan, Petroamazonas

Copyright 2014, Society of Petroleum Engineers

This paper was prepared for presentation at the SPE Middle East Artificial Lift Conference and Exhibition held in Manama, Bahrain, 26–27 November 2014.

This paper was selected for presentation by an SPE program committee following review of information contained in an abstract submitted by the author(s). Contentsof the paper have not been reviewed by the Society of Petroleum Engineers and are subject to correction by the author(s). The material does not necessarily reflectany position of the Society of Petroleum Engineers, its officers, or members. Electronic reproduction, distribution, or storage of any part of this paper without the writtenconsent 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 maynot be copied. The abstract must contain conspicuous acknowledgment of SPE copyright.

Abstract

Shushufindi is a mature oil producer field located in Ecuador; it was discovered in December 1968. For20 years was development by foreign oil industry and then was transferred to national oil company. InFebruary 2012 a contract was signed between Petroamazonas and Consorcio Shushufindi. Since this dateuntil now the production has been incremented from 34800 bopd to 75000 bopd.

The main Artificial Lift system applied to the field is electro submersible pump (ESP). High water cut,scale, low pressure, gas production, corrosion and other are problems that have presented in the wellsaffecting the run life of ESP.

A Multidisciplinary team has been created to work on a plan to improve the artificial lift systemperformance and increase production through the application of a monitoring and optimization process.

Initially failure frequency was reported due to tubing casing communication, cable failure or motorfailure. Therefore some optimization studies on these wells to use 12 and 18 pulses variable speed drive(VSD) instead of 6 pulses in order to minimize the harmonic distortion from the input side of the VSD.Where realize that, it is a common petroleum engineering practice to produce the oil with minimumoperating cost, while maintaining the facilities to serve efficiently for its design life time. In the meantimethe production rates of the well should be convenient to their capabilities. Any fault in the design of theproper production equipment for each well reduces the equipment life, increase maintenance cost, andworkover need and, therefore, increase the total oil production cost.

Performance indicators were established to evaluate the performance of electrical submersible pumpsfrom the beginning of the contract. The ESP average run life is 669 days.

On 2013 the percentage of indirect failures was 89.3% and direct failures 10.7%. Tubing CasingCommunication failure is the most important which represents 49.7%.Actually there are 140 producerswells completed with ESP of which 64% has remote monitoring. Optimization studies on productionparameters and operating conditions of ESP are continuously evaluated to perform increase of frequency,amperage consumption optimization, recommended operating range for ESP, downhole equipmentreplacement, equipment deeping, and others are done in order to increase production and ESP run life.

IntroductionWith current of oil prices it became necessary to reduce the cost of lifting the crude oil from the wells.This cost reduction is not feasible for each stage of the total oil production system; therefore theoptimization of each component in the production system is a must. Production optimization meant toapply an optimum analysis and comprehensive investigation of well production system, including theartificial lift system that expected to increase the oil production and reduce the operating cost.

The artificial lift systems are essentially in all brown field or mature field filed to transports reservoirfluid to the surface. Production optimization found to be an essential for the life cycle of each system inorder to extended run life, decrease and increase the cumulative production per well.

The applied artificial lift systems in our mature field case study include electrical submersible Pumps(ESP), gas lift, hydraulic pumping and sucker rod pumping. The dominant artificial lift method is the ESP,which is used in 143 wells and represents the 96% of the fields.

The failure and problems related to ESP and the success resulted from the applications of the systemoptimization is encouraged us to be selected to be the subject of this paper.

Additionally this paper will outline the process, tools and technologies utilized in a typical ProductionManagement/Optimization process and study. While many of the components are not new, the traditionalProduction Optimization study is evolving into a new process Production Management. The results of awell optimization project conducted by CSSFD in a mature field from oriental basin of Ecuador area aresummarized. The obstacles for production optimization will be identified.

ESP System overviewIn general ESP systems (Figure 1) incorporate an electrical motor and centrifugal pump run on a tubingstring and connected back to the surface control system and transformer via an electric power cable.Above the motor there is seal section, intake or gas separator or advanced gas handler, pump, and finallythe sensor. A flat cable (motor lead extension) connects to the motor at the upper pothead section. The flatcable spliced to a round or flat power cable above the ESP. This cable is then banded or clamped to thetubing all the way to the tubing hanger, where an electrical connection is made. A surface cable is thanconnected from this point to a junction box and finally to the VSD.

Figure 1—Typical ESP system

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ESP DesignFor the previous ESP design is necessary to be guided by the work flow that is detailed next and that itis shown in the Figure 2.

1. ESP design for both new wells and workover job

● Physical description: Casing size and weight; survey; tubing size, type, and thread; equipmentsetting depth (measured and vertical); depth of perforations (measured and vertical); restric-tions, unusual mechanical conditions.

● Production data: Static fluid level or static bottom hole pressure (Pws); Pumping fluid levelor flowing bottom hole pressure (Pwf); current producing rate; bottom hole temperature;GOR; WOR; tubing head pressure

● Well fluid data: API gravity; specific gravity of water.● Power supply: Surface voltage, phase, and frequency; electric line capacity.● Unusual conditions: Abrasives; Corrosion; Paraffin; Emulsion; scale-forming tendencies.● The design data are delivered in a normalized format and later discussed and agreed with the

reservoir engineers.

2. Productivity index determination (PI): Is a major factor in properly selecting the ESP system. Thedata required are an accurate Pws; a Pwf; and accurate oil, water, and gas production rates. Liquidlevel data can sometimes be used as a substitute for static and producing buttonhole pressures.Most oil and many water wells will not exhibit a true straight line PI relationship because of gasinterference and turbulence in the wellbore. Over moderate drawdowns, the PI calculation yieldingcapacity in bbl/d/psi drawdown produces a reasonable approximation of capacity. The recom-

Figure 2—ESP design workflow

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mended Vogel technique yields an inflow performance relationship capacity that is corrected forwellbore interference and gives a better indication of producing potential, especially at very highdrawdowns.

3. ESP systems selection: The selection of an appropriate (optimal) artificial lift system is dependenton: IPR of the well/reservoir, Capacity and operation of the artificial lift system(s),Capital cost,Operating cost, Servicing frequency (maintenance cost).

4. In these more complex applications, equipment selection calculations are more easily handled bythe dedicate software.

5. Total dynamic head (TDH): To determine the stages quantities required in the pump, must bedetermined for a projected rate. Is the sum of distance of vertical lift from the surface to thepumping fluid level � friction loss in the tubing � tubing discharge pressure at the wellhead.

6. Pump selection: Selection of the pump is based on the estimated pumping rate, TDH, wellconditions, and casing size limitations. The most economical choice is usually the largest series(diameter) that the casing will permit. Pump performance curves define optimum operating limitsfor various motor and pump sizes. The desired capacity should be within the optimum limits of thepump performance curves and nearest the peak efficiency of the pump selected.

7. Pump size: To determine the number of stages for the desired capacity, refer to the head capacitycurve (shown on the pump performance curves) for the selected pump type. These curves are basedon the performance of one stage in fresh water. The number of stages required is calculated bydividing the TDH by the head per stage from the head capacity curve for the type of pump selected.

8. Motor selection: Motors are available in a broad range of voltage ratings to provide the greatestversatility of switchboard and cable selection options. Setting depth is a determining factor inmotor voltage selection because of the voltage loss at a particular amperage and cable type. Motorvoltage selection must take into account voltage loss in the cable. Voltage loss is proportional tocable length and is a function of cable type and amperage. In deeper wells, a higher-voltage motorshould be considered because it requires smaller gauge cable than lower-voltage motors.

9. Motor size: The motor horsepower requirement is calculated by multiplying the horsepower perstage from the pump curve by the number of pump stages and correcting for the specific gravityof the well fluid.

10. Protector seals: There are two styles of protector seals available: bag and labyrinth. The patentedModular Protector seals combine these seal types in configurations of up to four chambers. Themotor horsepower, downhole temperature, and thrust bearing capacity should be taken intoconsideration when selecting a protector.

11. Cable: ESP power cable in flat and round configurations from 1/0 AWG through 6 AWG. Theoptimum cable size is governed by the amperage, voltage drop, and space available between thetubing collar and the casing. The best cable type is based on the buttomhole temperature and fluidsthat will be encountered in the wellbore.

12. VSDs: Offer greater flexibility than a switchboard to operate ESPs. Instead of operating the ESPat a constant speed, the ESP can operate at speeds greater or less than the grid power frequency.Changing the operating speed of the ESP can optimize the equipment performance and wellproductivity during the life of the well. Selection is based on voltage, amperage, and horsepowerratings, in addition to future requirements.

13. Transformers: Where the voltage of the primary system is not compatible with the requiredsurface voltage, a transformer will be required. Step-up transformers are available to increase a480-V line voltage to voltages of up to 5 kV.

14. At the end ESP provide complete design in a normalize format and later discussed and agreed withthe all SSFD group involved

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ESP Problems Analysis

Inadequate pump pressure intake

Generally, due to water irruption effect and lack of well data acquisition some pumps selection wasundersize. This let to produce the wells with high fluid level above the pump or high pump intake pressure(PIP). Consequently these not optimize the well production as per target due to design limitation. Figure3.

And the other hand, if the well had per any reason a low PIP the pump selection was oversized andoperative problems begin to show such as, PIP below the saturation pressure and consequent gas liberationthat gas locking the pump, motor heating for low refrigeration and others. Figure 4.

The general corrective action taken in such cases is to replace the existing pump with another biggeror smaller size as it is the case. The possibility is also analyzed, if the geometry of the well allows it, todeepen the pump. The challenge required workover and down time. All these reflect in the lifting cost.

Figure 3—High pump intake pressure over bubble pint

Figure 4—PIP below bubble point

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Reservoir problemsFor depletion drive reservoirs and or ineffective water support, ESP pumped off stopped as a result as aunder load. This append frequently. Start and stop ESP usually led to motor and or cable failures.Avoiding this, usually well is chocking back and or switch to timer mode. Both corrective actions usuallywere not of long duration.

Traditionally it is preferred to stimulate the sand producer, by means of an acidification or with ahydraulics fracture job. It is usually changed also sand producer or to analyze the option of enlarging theproducer intervals. This proposal also required workover, downtime and increment the lifting cost.

Tubing casing recirculationThe Tubing-Casing recirculation is the most common failure that affects the life expectations of the ESPequipment and the main reasons so that it happens are:

1. Tubing leaks.2. Y-Tool blanking plug failure.3. Sledding sleeve side door bad closed.

By means of the monitored system in real time that allows analyzing the information registered by thebottom sensors, is possible to detect in early form this failure type and in that way to take opportuneactions to avoid that the tubing is cut by effect of the critic erosion velocity.

In the Figure 5 are possible to observe like they behave trend how the motor temperature (Tm) increase,the intake pressure (PIP) increase and the discharge pressure (Pd) diminishes, when tubing-casingcommunication exists.

Of the three mentioned failures, the main ESP failures are related to indirect failures predominatingmechanical problems like tubing leaks.

The action plans taken to mitigate the tubing string failures were the following: metallurgy upgradesfor pipe endurance and introduction of Premium threads along with the use of automated torque tools inorder to improve connection integrity. More specifically tubing string designs were changed from L-80EUE to Premium L-80 with a 1 % Cr.

Sand ProductionIn case of well was producing fine sand, what generally happens later on to a hydraulics fracture work,of ESP subject to partial pump sticking in some wells. This problem occurs after a certain period ofoperation and the stuck happened during trying to restart the well after any maintenance or power supply

Figure 5—Real time ESP monitoring

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failure. To rerun the ESP usually the motor rotation is reversed to help the pump to rotate and start thesystem. If not succeeded we forced to use bigger generator to start the pump but this might cause motorfailure. So forced to perform work over to replace the pump.

The excessive amount of rain is the direct cause of the premature life cycle of the ESP’s due to fieldelectrical system failure and shutdown’s.

Scale and corrosion problemsThe previous flow assurance studies have demonstrated that production fluids (oil and water) of most ofthe wells they have tendency to scale precipitate and / or corrosive attack. When the scales are depositedthey make in the first place in the motor walls that makes diminish the transfer heat capacity to thecirculating fluid and in consequence the motor is overheating.

When the production water mixes with the CO2 contained in the gas of the well, a corrosiveenvironment takes place and the fluid attacks the internal components of the pump and the tubing string.

Both effects diminish the expectations of life of the equipment sensibly ESP. The preventive actionsto avoid the scales formation and to prevent the acid attack consist on injecting chemical products antiscales and anti-corrosive through capillary tubes strategically located in the production string.

Water drivingThe field of our case study is under saturated and is characterized as having two simultaneous drivingmechanisms. The first mechanism is associated with solution gas drive, and the second is associated withan active bottom and lateral aquifer. This latter mechanism offers high recovery factors that oscillatebetween 25 and 30% and high water cut in most of the wells, especially in those producing from the “T”sand. This well required to design the ESP system to produce almost the same water volume with adequatewell head pressure to match the required water and pressure for the selected flow line diameter, longitudeand storage tanks capacity in the production station. Any change in one or more of the injector will reflecta back change in the ESP output. Since the ESP was working with a VSD at fixed frequency, the onlyallowable change in the ESP output (rate and/or pressure) is to chock up or down the well and to workwithin the pump operating range. In most cases we faced with a decline in the required water volume bythe production station. In all action taken we found that total system efficiency for the ESP negative effect.This results in high power consumption. The average wells running lives was shorter than expected.

Optimization process overviewIn the whole oil industry the main objective of production and reservoir team is very clear and simplystated, production management is the step by step, process of maximizing oil production over the longterm while minimizing total production costs. The overall goal is to achieve the optimum profitabilityfrom the well, reservoir or field.

To achieve and maintain this was essential to evaluate and monitor many aspects of the productionsystem: production equipment, surface and downhole; the wellbore; the sand face; the reservoir; theproduced fluids; and the production history.

To perform production management economically and efficiently is necessary: expertise in all aspectsof the production system, information management systems and electronic data acquisition.

For production optimization the production engineering group and reservoir team carry out thefollowing activities:

1. Dedicate the time required to extract well file data and relevant technical information.2. Baseline data was unavailable to determine which wells required evaluation, or to what extent

testing was required.

In response to these factors, submitted a proposal to conduct a production management study toestablish a baseline of operating conditions for this group of wells:

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Step 1 Conduct a comprehensive well-by-well file investigation. Assemble all required and relatedmechanical and production data, plus summarize the completion and workover history.

Step 2 Perform field testing and data acquisition:

● Flow rate tests.● Pressure test.● PVT data fluid.● Intake pressure and discharge pressure, in same case Echometer survey.● Meet with field personnel.

Step 3 Perform technical analysis and evaluation:

● In-depth Echometer analyses.● Producing pressure calculations.● Inflow Performance Relationship (IPR) calculations.● Well model construction on steady-state, multiphase flow simulator.● System review and evaluation.● ESP system design and redesign.

Step 4 Summarize recommendations:

● Identify potential production gains● Extend equipment life.● Reduce power costs.● Reduce workover frequency.● Optimization wells candidates portfolio.

In order to have the most information in a single data base and reduce the time searching, filtration andvalidation information A digital oil field locally known as “Centro MIA” (Centro de Manejo Integrado delActivo, spanish for Asset Integrated Management (AIM) Center) was create and implemented in order toaccess in an easy way the technical and operational information for production optimization. This AIMconsists of an integrated solution composed of several interacting components; it is the functionalreal-time monitoring system with capabilities for monitoring drilling, workover and production opera-tions. The engineering workflows comprise the design and development of solutions that address businessprocess definition needs and automation of engineering tasks. Different workflows have been developedfor the AIM covering facility monitoring, drilling monitoring and surveillance, workover monitoring andsurveillance, production surveillance, ESP monitoring and optimization and well test validation, to namea few. The workflows are deployed within a collaboration environment and supported by the latestinformation technology (IT) infrastructure in order to realize their digital potential.

ESP monitoring and optimizationThe electrical submersible pump (ESP) systems deployed in our field use a new-generation pump digitallyenabled with built-in sensors, surface power and communications infrastructure and remote surveillanceand control equipment. Linked to personnel with diagnostic and remediation skills back in the IAMCenter, the communications system provides continuous internet access to real-time downhole pressure,temperature, and pump system data over a secure connection. In just the first two months after systeminstallation and workflow deployment, the technology helped to identify damaged equipment in a well thatwas causing decreased production in the monitored well.

The monitoring system for the ESP wells (Figure 6) required an interface to the ESP surface controllersand the ability to extract critical motor ESP parameters such as motor frequency, motor current, motor

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voltage, and other motor parameters. The system also transmits various downhole measurements such aspump intake and discharge pressure and temperature, vibration, or currents. Wellhead pressure andtemperature are also available.

The ESP surveillance allows well behavior to be identified before unwanted events take place in aproactive manner through operation envelope alarms and multivariable trending monitoring. The team inthe IAM can then diagnose potential problems such as gas block, tubing-casing communication (recir-culation), excess backpressure, scale problems, formation damage, etc.

Additional benefits reported through the use of this workflow so far have been:

– Reduction in production losses though a quicker reaction time from failure to “back in production”shorter cycle.

– Reduction in production losses and costs through preventive problem detection– Online system for well health diagnosis that allows directing the issues to either reservoir or

wellbore specialists.– Online real-time system for well IPR and productivity determination. Also a source for pressure

transient test analysis and diagnosis of reservoir properties. This additional information gatheredthrough the pump permanent downhole sensors come at a marginal cost when compared to therequired well interventions needed before.

Production engineers can very quickly determine, in real time, whether a well has been stabilized andworking well for swift rig release after a job thus saving rig time.

ESP Diagnosis and OptimizationIn order to diagnose the problems more common in the field that are presented in the ESP equipment, thesteps should be continued enumerated next and detailed in the work flow that is shown in the table 1 andFigure 7.

Figure 6—ESP monitoring and optimization workflow steps

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1. Daily revise and update the OFM database. Daily monitoring the production performance of eachwell. Identify well with production loss. Review weekly artificial lifts report. Field Engineerprovides updated weeks report.

2. Oil field manager PASS process: Production Engineers developed a fit for purpose processes toidentify wells candidates to optimization.

3. 1.1. Production rate: Static fluid level or Pws; pumping fluid level or Pwf; Present producingrate; Bottom hole temperature; GOR; WOR; Tubing head pressure.1.2. Operational parameter: well head pressure (WHP), annular pressure, Intake pressure, Intaketemperature, Amperage, Motor temperature, THP, Frequency, Vibration.1.3. Well fluid data: API gravity of oil; Specific gravity of water.1.4. Power supply: Surface voltage, phase, and frequency; Electric line capacity.1.5. Unusual conditions: Abrasives; Corrosion; Paraffin; Emulsion; Scale-forming tendencies.1.6 Physical description: Casing size and weight; Survey; Tubing size, type and thread; Equip-ment setting depth (measured and vertical); Depth of perforations (measured and vertical);Restrictions, Unusual mechanical conditions.

4. Troubleshooting: Apply the Artificial Lift Technical Service Manual / Troubleshooting in orderto verify the ESP behavior and to apply the correctives actions. Refer to the Table 1.

5. Downhole monitoring: In order to ESP system and completion performance monitoring; Wellswith potential startup or instability problems; Wells with changing productivity and sand faceconditions; Reservoir drainage and depletion monitoring; Enhanced well-intervention planningand Verify if the Pwf �Bubble point (BP) and if the GOR is high. If the annular pressureovercomes the 200 psi, proceed to periodic annular degassing.

6. GOR: Verify if the well candidate produce with high GOR or Pwf�BP. In this case to proceedto periodic annular degassing.

7. WC: Verify if the well candidate produce with high water cut, bigger than 80%. Reviewingperiodic production well test in order to define the next steps.

8. In accordance with the troubleshooting results, artificial lift field engineer presented an operative

Table 1—Cause and effect analysis

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program with recommendations to modify operative conditions in order to production optimiza-tion.

9. Artificial lift field engineer and operator modified operatives ESP parameter according withoperative programs recommendation

10. Workover engineers and artificial lift field engineer verified if the well has scales precipitation inthe tubing string and ESP.

11. Production engineers, Artificial lift and operator provide an operative report to Reservoir engineersand Workover engineers in order to analyzed the action plan

12. Reservoir engineers programmed Workover job or rigless operation to water control or any otheraction plan

13. Workover engineers programmed a rig less operation for clean-up tubing string or ESP.

ESP Optimization using VSDThe VSD is a powerful tool in ESP operation that can change the rotational speed of the motor bychanging the frequency of the AC power before sending it downhole to the ESP. By changing therotational speed of the pump, the operating range is greatly expanded. The essential principle of varying

Figure 7—ESP diagnosis and optimization work flow

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the motor rotational speed is to improve system performance and ensure that when downhole conditionsor pump performance change, the system can have the flexibility to allow control well performance.

In this type of artificial lift system in order to upgrade or downgrade pump size to match will wellproductivity is a must to replace the pump and this required to workover the to pull the tubing and bottomhole ESP assembly.

The 12 and 18 pulses VSD are installed in the entire well producing in order to avoid harmonicdistortion and provide to the motor winding a sinusoidal wave form. Additionally, while voltage appliedto the motor winding is not sinusoidal, the motor current is a function of the average voltage applied. Sothe motor current is very sinusoidal in nature. In other word, the motor will see a sinusoidal current andwill rotate smoothly due to the sinusoidal current.

This tool is very until and is use under depletion drive reservoir and for the well that produce with highwater cut with the aims of: reduction of WO job, increase ESP run life and maximizing well production.

Production optimization with new technologyMost of the wells in SSFD have been completed in both “U” and “T” sands with a selective completionthat allows producing one layer at the time. This is not suitable to reach the objective of higher incrementalproduction leaving a negative economic impact to the project. Since the CSSFD contract is based onincremental production, it is of imperative to produce reservoirs simultaneously. In general is possible torun Dual Completion but the operation is complicate, especially when one of the ESP (Upper or Lower)has problem and failure, beside the cost is high. In order to optimize current production and accelerateproduction without lowering the field recovery factor we were looking a new opportunities and technol-ogies to implement and manage separate production between sand according with government regulationthat don’t allow to produce two sand in comingled, in that way we found a new technologies to applynamed IntelliZone, that consist a in compact system which contains a packer, a flow valve and a seriesof gauges that measure annular and tubing pressure and temperature plus a sensor capable to provide realtime valve position. Where is possible at the same time and with a singled ESP produce two sandsimultaneously with the following benefits:

● Ability to determine the contribution from each sand to satisfy the requirements of Ecuadorianregulatory agencies.

● Optimization of the production and the management processes of the reservoir.● Remote monitoring capability.● Control of the exploitation / injection at the bottom of the well without physical intervention.● Reduction of the number of well interventions needed for basic flow control, dedicated to combat

the premature water and gas irruption.● Protection of the sands by isolating them mechanically while doing well interventions, i.e. ESP

replacement minimizing any inferred well damage.● Allow simpler and notoriously less expensive future well interventions.● Reduced operational time in approximately 11 days (40%) as a result of the simultaneous

operations compared with a Dual Completion Installation.● Allowed down hole chemical injection at the sand face.

Inspection and Failure AnalysisAfter the ESP Failure, Pull operations are performed the ESP equipment is send to the Service Center inorder to find the root cause of the incident while a complete process of Dismantle/Inspection and failureanalysis is done.

With the conclusive results of the investigation the company provides high value information to theclient and to itself in order to have remedial work plans that can avoid similar failures in future.

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A workflow and process is following during this step after the failure:First the collection of all evidence, input data, ESP design comparison between real production, run

reports and records, production data and ESP parameters during the run life of the ESP, well geometric,frequency, BSW, solids or scale production and treatment, gauge data start up quantities, tubing test,Surface Setup parameters (overload, underload alarm, etc).

During the pull evidence as scale, solids, tubing holes, need to be kept, and a formal pull report needto be done and distribute.

Inspections at the service center with the presence of the client need to be set and all the logistics forthe activity. For testing of the equipment prior the inspection is mandatory to have client approval at thispoint in order to execute the inspection, it is recommended to have an inspection form and take photosof evidence for the execution of a final report. After the equipment is test and dissemble the analysis ofroot cause needs to be performed as the main part in the investigation in order to inform the client andavoid similar failures.

Some of the Failure mechanisms are corrosion, Upthrust wear, Downthrust Wear, Torsional Damage,Erosion, Heat, Deposition, Human errors, etc.

Root Cause, after the evidence you need to determine what cause this problem, if there was a solidsproblem, this produce pump stuck, wear in the stages, etc. Figure 8.

Conclusions

● With this integrated process was possible to study Shushufindi & Aguarico field,finding in a short time 99 recommendations in oil well that could increase 10500BOPD, by increase extraction or change de ESP design.

● Synergistic combination of internal and external data sources results in an excellentcombination of broad standards and detailed information.

● Point and shoot tools are required to provide answers for users of any level. In mostcases, the answers and trends from these tools is what is needed for business andstandard customer questions.

● Quick and objective conclusions are developed by correlating well interventionswith a set of results; usually well production. Large amounts of data can be quicklyprocessed to form “first pass” conclusions on a macroscopic basis.

Figure 8—ESP diagnosis and optimization work flow

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● The AIM implemented in the relational database is the most powerful data man-agement solution when the data model is extended.

● Experience in the field has demonstrated that very positive results can be obtained,even in mature producing areas, with a systematic optimization program thatexamines all aspects of the production scheme.

AcknowledgementsThis work has been an achievement of a multidisciplinary team work, integrating the groups Productioningenierind and artificial lift from Consorcio Shushufindi, Schlumberger and Petroamazonas.

Beside we want to thank Consorcio Shushufindi and Petroamazonas, for letting us publish this article.

References● Brinded, M. 2008. Smart Fields-Intelligent Energy. Paper presented at the Intelligent Energy

Conference, Amsterdam, The Netherlands, 25 February.● Garcia, A., Sankaran, S., Mijares, G., Rodriguez, J. and Saputelli, I. 2008. Real Time Operations

in Asset Performance Workflows. Paper SPE 111990 presented at the Intelligent Energy Confer-ence and Exhibition, 25-27 February.

● Milligan, G., Deutekom, M., and Buchan, C.: “Guided Workflow for the Digital Oil Field-APractical Example”. 2008 SPE intelligent Energy Conference and Exhibition, Amsterdam, 25-27February 2008.

● Ohen, H. A., Erian, A., Ali, L., Guzman, D., Guerrero, O., Ochoa, J., Valdivieso, L., “IntegratedReservoir Study of Shushufindi Field - Dynamic Modeling”, SPE/DOE Fourteenth Symposium onImproved Oil Recovery, Tulsa, Oklahoma, USA, 17-21 April, 2004. SPE 89465.

● Steele, R.D.: “Engineering and Economics Used to Optimize Artificial Lift Methods”, Oil & GasJournal. (Dec. 6, 1976) 107–16.

● Thomson, A.: “Deploying Field the Future on Major Projects”. 2008 SPE intelligent EnergyConference and Exhibition, Amsterdam, 25-27 February 2008.

Nomenclature

AIM: Centro de Manejo Integrado del ActivoBOPD: Barrel oil per daysBP: Bore hole pressureCSSFD: Consorcio ShushufindiESP: Electrosumergible pumpFDP: Field development planGOR: Gas Oil RatioIPR: Inflow performance relationshipIT: Information TechnologyPd: Discharge PressurePIP: Intake PressurePWF: Fluid well pressureSSFD: ShushufindiT: Sand “T”THP: Tubing head pressureU: Sand “U”VSD: Variable speed driveWC: Water Cut

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WHP: Well head pressureWHT: Well head temperatureWO: WorkoverWOR: Water Oil ratio

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