Copyright 2003, Society of Petroleum Engineers Inc. This paper was prepared for presentation at the SPE Annual Technical Conference and Exhibition held in Denver, Colorado, U.S.A., 5–8 October 2003. 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 Permanent monitoring of downhole equipment and production in artificial lift wells is an excellent method of diagnosing conditions and determining the appropriate approach to avoid loss of production or of the well. Belayim Petroleum Company in Egypt (Petrobel) has used permanent monitoring sensors since 1994. The systematic data are used by the reservoir and production engineering staff to tackle problems such as high failure rate, sand fill-up, scale, ESP wear, and electric failures. Petrobel currently has twenty downhole gauges, and 8 other systems are waiting associated accessories before installation. Each permanent gauge sends nine measurements per minute to the surface in real time yielding an incredible volume of information. Downhole gauges supply accurate information about the reservoir, downhole, and the pumping system. This knowledge, in turn, is used to increase the run life of the artificial lift system through optimization of the reservoir pressure and artificial lift syste m performa nce. This paper demonstrates the long-term benefits of using subsurface permanent gauges to complement artificial lift equipment and provide real-time data to optimize well and/or field production. Case studies illustrate both offshore and onshore problems. Examples are given of wells that have been converted into successful artificial lift completions through proper interpretation of the gauge measurements and use of the information to optimize production. This paper brings data interpretation to a new level of prediction, which enhances economics and minimizes risk in production operations, especially offshore. INTRODUCTION Surface measurements alone cannot easily distinguish reservoir effects from effects of the submersible pumping system. The multistage centrifugal pump is driven by an electric motor. The pump and motor are normally suspended from the production tubing with the motor positioned below the pump, which discharges directly into the production tubing. 1 The pressure and temperature gauges below pump provide information at the interface between the reservoir and the pump. Control and monitoring of pump performance are essential to achieving long run life. Using real-time data of downhole and surface parameters, personnel can maintain the equipment within its recommended operating range and have the capability to detect abnormal operating conditions and take appropriate actions that avoid failures. Historical trend analysis can also be used to identify changes in pump and reservoir performance. This analysis, therefore, provides input data to assist reservoir modeling. 2 Monitoring of the pumping system and well performance is achieved through the use of downhole multiple gauges (multisensors). A multisensor provides a 'semi-redundant' measure of flowrate, intake pressure and temperature, discharge pressure, vibration, leak of current and motor winding temperature. Digital signal processing techniques are used to eliminate noise and measure the frequencies with a high degree of accuracy and resolution. The millivolt-level signals, which were once unidentifiable, can now produce pressure and temperature measureme nts with resolutions suitable for reservoir analysis. In fact, as the frequency and fidelity of the data increase, the accuracy and precision of the model increase as well. The use of permanent downhole monitoring systems is increasing globally, both in numbers of installations and in new applications for the technology. Although applications were once centered around reservoir management, these systems are now being used for pump control, gas lift control, prevention of workovers, improve fracturing operations, better SPE 84138 Downhole Permanent Monitoring Tackles Problematic Electrical Submersible Pumping Wells S. Macary, SPE, I. Mohamed, SPE and R. Rashad, SPE, Schlumberger , M. El-Noby, M. A/Latif, I. Awni and M. A/Khalek, Petrobel
Transcript
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Copyright 2003, Society of Petroleum Engineers Inc.
This paper was prepared for presentation at the SPE Annual Technical Conference andExhibition held in Denver, Colorado, U.S.A., 5–8 October 2003.
This paper was selected for presentation by an SPE Program Committee following review ofinformation 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 any
position 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 ofPetroleum 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 300
words; 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.
ABSTRACTPermanent monitoring of downhole equipment and production
in artificial lift wells is an excellent method of diagnosingconditions and determining the appropriate approach to avoid
loss of production or of the well.
Belayim Petroleum Company in Egypt (Petrobel) has used permanent monitoring sensors since 1994. The systematic dataare used by the reservoir and production engineering staff totackle problems such as high failure rate, sand fill-up, scale,
ESP wear, and electric failures.
Petrobel currently has twenty downhole gauges, and 8 othersystems are waiting associated accessories before installation.Each permanent gauge sends nine measurements per minute to
the surface in real time yielding an incredible volume ofinformation.
Downhole gauges supply accurate information about the
reservoir, downhole, and the pumping system. Thisknowledge, in turn, is used to increase the run life of the
artificial lift system through optimization of the reservoir pressure and artificial lift system performance.
This paper demonstrates the long-term benefits of usingsubsurface permanent gauges to complement artificial liftequipment and provide real-time data to optimize well and/or
field production. Case studies illustrate both offshore andonshore problems. Examples are given of wells that have been
converted into successful artificial lift completions through proper interpretation of the gauge measurements and use ofthe information to optimize production. This paper brings data
interpretation to a new level of prediction, which enhances
economics and minimizes risk in production operations,especially offshore.
reservoir effects from effects of the submersible pumpingsystem. The multistage centrifugal pump is driven by anelectric motor. The pump and motor are normally suspendedfrom the production tubing with the motor positioned belowthe pump, which discharges directly into the production
tubing.1 The pressure and temperature gauges below pump
provide information at the interface between the reservoir andthe pump.
Control and monitoring of pump performance are essential toachieving long run life. Using real-time data of downhole andsurface parameters, personnel can maintain the equipment
within its recommended operating range and have the
capability to detect abnormal operating conditions and takeappropriate actions that avoid failures. Historical trendanalysis can also be used to identify changes in pump andreservoir performance. This analysis, therefore, provides inputdata to assist reservoir modeling. 2
Monitoring of the pumping system and well performance is
achieved through the use of downhole multiple gauges(multisensors). A multisensor provides a 'semi-redundant'
measure of flowrate, intake pressure and temperature,discharge pressure, vibration, leak of current and motorwinding temperature. Digital signal processing techniques are
used to eliminate noise and measure the frequencies with ahigh degree of accuracy and resolution. The millivolt-levelsignals, which were once unidentifiable, can now produce
pressure and temperature measurements with resolutionssuitable for reservoir analysis. In fact, as the frequency andfidelity of the data increase, the accuracy and precision of themodel increase as well.
The use of permanent downhole monitoring systems is
increasing globally, both in numbers of installations and innew applications for the technology. Although applicationswere once centered around reservoir management, thesesystems are now being used for pump control, gas lift control,
prevention of workovers, improve fracturing operations, better
SPE 84138
Downhole Permanent Monitoring Tackles Problematic Electrical SubmersiblePumping WellsS. Macary, SPE, I. Mohamed, SPE and R. Rashad, SPE, Schlumberger, M. El-Noby, M. A/Latif, I. Awni andM. A/Khalek, Petrobel
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2 SPE 84138
understanding of downhole injection, and many otherapplications related to optimizing production operations. After processing of the incoming signals, the data virtually looks
like as it comes from a sensor sitting two feet apart and notkilometers away at the bottom of a well. 3-4
Petrobel has more than 30 years of experience with electrical
submersible pumps. Their use of downhole multisensors datesto 1995, when they installed Type 0 sensors in some marine
and land wells that produce Belayim field. Five years later,they changed to Type 1 multisensors to obtain readings of the
pump discharge pressure. Almost 10% of the wells with these pumps also have downhole gauges.
Figs 1 and 2 show the geographic location and the daily
production of Belayim field for about half a century. Newdiscoveries and high levels of activities characterize the period
1975-1995. The daily production peak (250 MBOPD) wasreached in 1995. After that date natural depletion began,resulting from water-cut increase and common problems of
maturity. This, in turn, reduced the number of pumps thatexceeded a run life of 1000 days for the last 5 years by
about 40%.
Belayim Field
Belayim fields are Belayim marine, Belayim land and RasGarra field. Belayim marine field has three zones: Zone II,Kareem/Rudies formation and Premiocene formation. Themain production zone is Kareem/Rudies formation, which is amulti-layered reservoir producing around 49% of the total
Belayim production. The average reservoir pressure is 1,500 psi at datum (8,400 ft). The initial reservoir pressure was
4,200 psi at datum. The bubble point pressure (BPP) is 1,300 psi and the recovery factor (RF) to date equals 48% as a resultof using water injection (boundary injection) to maintain the
pressure around BPP.
Belayim land field consists of eight zones: Zone I, Zone II,Zone III, Zone IV, Zone IV-A, Zone V, Premiocene and Sidri.
The main production zone in Belayim land is Zone IV, producing 12% of total Belayim production with a RF of 26%.The average reservoir pressure is 1,600 psi at datum 7,900 ft.The initial reservoir pressure was 4,000 psi at datum, and BPPwas 950 psi. The reservoir is under water flooding.
DISCUSSION
ESP Downgrading or Upgrading
In a new well or new installation startup, the pressure-temperature gauge provides early measurement of well productivity. Oversizing in new wells can lead to ESPdamage. This is readily detected by low flowing bottomhole
pressure (BHP) followed by an increase in temperatureresulting from lower-than-expected flow rates. A variable-speed drive can be installed to extend the pump operatingrange, or low-rate intermittent production can be maintaineduntil the well cleans up to the expected flow rate.
Well BM-67 shows the added value of multisensor real time
measurements. The intake pressure performance shows steepdepletion with a fluid flow rate of 150 m3/d. This highdepletion rate indicated there was no pressure support and thatthe block penetrated by this well was too small to be drained by another producer, which in turn modified the Companystrategy. Moreover, to maintain production, the operating
conditions were changed to downgrade the pump without pulling it to surface. Fig. 3 illustrates the pressure and production performance of this well. When the production wascut to 50 m3/d in August 2001, the pressure attitude became stable.
An opposite situation was encountered in Well BM–34. Waterinjection approached this well early in 2000 as indicated by anincrease in the intake pressure and a decrease in producedwater salinity and gradual increase in W/C (Fig. 4). Thereservoir pressure increase resulted in a drawdown increaseand hence more fluid flow. A decision was made to upgrade
the ESP. See Table 1 for specifics.
Table 1 – Upgrading Criteria
Before After
Pump Type & Size Reda-GN-4000 Reda-GN-7000
Q, bbl/d (G/Net) 2,830/2,320 5,280/4,330
HP 250 450
Stages 259 326
As seen from Table 1, the flow rate doubled and the wellmaintained this production level for more than 1 year with aW/C of 20%. A simple feasibility study can determine the gainfrom the sensor compared with the cost of its downloading andeven the cost of upgrading the pump.
Fig. 1 – Belayim Field Location Map
N
ABU ZENIMA
ABU RUDEIS
FEIRAN
BELAYIM
RAS GHARIB RAS GARRA
GULF
OF
SINAI
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SPE 84138 3
Formation Identification
Additional benefits of multisensors pressure measurements areimproved to assist reservoir management and maximum
recovery of reserves; e.g., a low reservoir pressure can beraised by more water injection to the area. 5
This is the case of Well M-84; 600-psi drop in the intake
pressure within 5 months resulted in a decrease in flow ratefrom 400 to 140 m3/d. This fast depletion led to a decline in
the area development plan; no new drilling due to limited block extension. Therefore, the well was switched to produce
from the upper reservoir (Rudeis) at a rate of 500 m3/d.
Reservoir Pressure Monitoring
Wells that have been on production for a considerable time
have steady-state pressure conditions. Because the productionis maintained at a constant rate by the pump, any pressure
change is the direct result of interference from another well.Injection-well interference tests give early indications ofinterwell communication and add confidence to development
planning decisions.
The production from Well BM-68 was at a critical level, so thewell was shut in to observe the multisensor pressure readingand evaluate the performance of the near injector in supportingthe reservoir pressure. Fig. 5 illustrates a 200-psi pressureincrease. Well BM-34 is another example of a downholemultisensor used to monitor reservoir pressure performance.
Pump Efficiency
For a conventional BHP survey with gauges run on slickline, awell must be shut in for a minimum of 36 hr while gauges arerun and retrieved, exclusive of a pressure buildup period. The
benefit of having BHP data continuously available at surfaceis that the data enable optimal operation of ESP. If the pumpsare operated out of range, premature failures will occur. Theworkovers needed when these pumps fail often takes 7 days,and oil production is often deferred for considerably longer because of rig priorities. 6
The pump’s “apparent efficiency” is defined as the ratio of theactual head and the theoretical head. The flowmeter system
computes this parameter in real time. The effect of any blockage around the suction ports or between them and thefirst-stage impeller is manifested as an apparent reduction in pump-head efficiency.
Well 113-A-11 is the prototype example of this situation.
Having the intake pressure the Nodal Analysis follows at the pump intake as nodal analysis point (NAP). Fig. 6 shows thematch to be far from reality (intersection apart from theoperating point). Adjusting the head factor to 0.6 improved the
match. This adjustment and the production rate test indicatedthere was a loss in pump head and that the ESP was
functioning close to the upthrust boundaries. Fig. 7 illustratesthe performance curves of the used pump.
Tubing Leak
Upward trends in BHP may be caused by pump stage wear ineither upthrust or downthrust, diffusers spin, lost pump stages
(a result of pumpshaft shear, scale or solids deposits), andrecycling of pumped fluids through a leak path below the top packer element (broken packer seals, leaking pipe connection,
unseated adaptor tool plug, broken seals, washout in pump body).
Well 113M-76 is obviously an example of a tubing leak. By
the end of May 2001, the intake pressure had jumped to 1,300 psi (a more than 150-psi increase). This was accompanied by adecrease in the flow rate. A lack of change in salinity indicatedthere was no change in the reservoir conditions and the problem should be a borehole one. This case was interpretedas either intake plugging or tubing leak. There was no packer
in the well, so the production loss from tubing to annulusextended the bottom of the hole, causing a rise in the P wf andthen decreasing the drawdown and the flow rate. Alternatively,scale plugging might lead to higher fluid static level and againhigher Pwf . The well was shut in for inspection and a hole inthe tubing was found 27 m above the pump.
Drawdown and PI
Analysis of pressure losses in the completion system, such asdrawdown pressure between the reservoir and wellbore,completion skin, and tubing pressure losses providesinformation to optimize well production. 7
Considering the intake pressure and the static reservoir pressure, the reported PI in Well 113-A-11 was obviouslywrong. When the static head exerted by the fluid column in theinterval between the perforation and the pump intake wassubtracted from the reservoir pressure the Pwf ; was higher thanexpec ted, which indicated the drawdown was smaller than
thought. When the actual production rate was substituted inthe famous PI equation, the actual PI was found to be morethan 600% higher than originally calculated.
Intake and Discharge Pressure
There are many benefits to recording simultaneously the
intake and discharge pressure; e.g., pump performancedegradation with gas and fluid viscosity, and multiphase pressure drop in the tubing in deviated wells with gas. Pumpand tubing performance can be separated and the correctvalues can be assigned to each component for diagnosis andthen design improvement. Issues in Well Abu Zenima-13-1
(AZ-13) were actually resolved by running a Type-1
multisensor to measure the discharge pressure simultaneouslywith the other parameters.
Petrobel installed the first Type 1 multisensor in September2000 in Well AZ-13 to evaluate and solve the downhole
problems that were requiring workovers every 3 months. Inthe first few hours of operation the sensor picked up a highESP motor temperature (350
oF), and the pump was saved.
Fig. 8 illustrates the effect of unreal reported data on wellsimulation using the multisensor data. The analyses andinterpretation of multisensor data, using gradient traverse plot
technique, determined an adjustment of productivity indexvalue from 5 to 0.8 STB/D/psi and water cut from 31% to
17%. This match is shown in Fig. 9.
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4 SPE 84138
In addition, Well AZ-13 produces viscous crude with 21.7oAPI gravity. The initially installed ESP had radial flowimpellers, which are not appropriate for this crude, and there
was a loss in the pump head as illustrated in Fig. 8. The poump was redesigned with mixed flow impellers to prevent
the partial plugging of the small radial flow impellers.
CONCLUSIONS1. Permanent bottomhole multisensors have achieved
adequate resolution and reliability in wellswith ESP's.
2. Well productivity and pump performance have beenmonitored directly with pressure- temperature gaugesdata. This monitoring has improved the operating
efficiency of the pumps, enabling production targetsto be achieved.
3. Reservoir management has been enhanced with datafrom downhole multisensors. Reservoir simulation
models have benefited from improvedreservoir description.
REFERENCES
1. Jeff Spath and Alex D. Martinez: “Pressure TransientTechnique Adds Value to ESP Monitoring,” SPE paper # 54306 presented at the Asia Pacific Oil &Gas Conference and Exhibition held in Jakarta,
Indonesia, 20-22 April 1999.2. S.J. Harrall and D. Nevelsteen: “Gannet E Subsea
ESP: The Application of Technology in Practice,”SPE paper # 50596 presented at the SPE EuropeanPetroleum Conference held in Hague, The
Netherlands, 20-22 October 1998.3. Kamal el Chiriti, Terrence G. Moffatt and Colin
Bussiere: “Permanent Downhole Monitoring forExtreme Temperature and Pressure,” SPE paper #71593 presented at the SPE Annual TechnicalConference and Exhibition held in New Orleans,Louisiana, 30 September –3 October 2001.
4. M.P.Tibold, S. Simonian, M. Chawla, et al.: “WellTesting with a Permanent Monitoring System,” SPE
paper # 63079 presented at the SPE Annual TechnicalConference and Exhibition held in Dallas, Texas, 1-4October 2000.
5. J.D. Gallivan, L.J. Kllvington, and A.J. Shere:
“Experience with Permanent BottomholePressure/Temperature Gauges in a North Sea Oil
Field,” SPE Production Engineering, November1988, pp. 637-42.
6. Alan Brodie, Dr. Joe Allan, and Gardiner Hill:“Operating Experience with ESP’S and Permanent
Downhole Flowmeters in Wytch Farm ExtendedReach Wells,” SPE paper # 28528 presented at the
SPE Annual Technical Conference and Exhibitionheld in New Orleans, LA, U.S.A., 25-28September 1994.
7. Javier Ballinas: “Evaluation and Control of Drilling,
Completion and Workover Events with PermanentDownhole Monitoring: Applications to Maximize
Production and Optimize Reservoir Management,”SPE paper # 74395 presented at the SPE InternationalPetroleum Conference and Exhibition held in
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