The document discusses the performance of electrical submersible pumps (ESPs) in the Messla oil field in Libya. It finds that ESP run life has sharply decreased in recent years due to a gap between reservoir management and ESP system reliability. To improve the system for the next 5-10 years, it recommends fixing pump setting depths based on predicted reservoir pressures. This will improve reliability, better prepare stock inventory, and reduce costs.

1. Messla Electrical Submersible Pump Future Performance
Production Engineer. S. Khalifa.
Abstract: Artificial Lift Systems widely used in Libyan oil fields specifically Electrical Submersible
Pumps (ESP). The systems occupied almost 80 % of Libyan oil fields production time, equipment,
efforts, and budget. ESP stakeholders and activities supposed to be a part of the comprehensive oil
field development management and planning stages. Therefore, identifying each of those stages and
the people who take part in the processes is fundamental. The paper revises the ESP system
performance in AGOCO-Messla oil field. The conclusions showed that lately sharp decreased pump
run life is referred to a credibility gap between reservoir development management and the system.
Therefore, by predicting the next 5 to 10 years’ ESP performance we recommend to fixe setting pump
depth just like initial situation was to improve the system reliability, stock inventory and budget costs.
Introduction: Practically, ESP operations experiences in mature oil fields suppose to
exhibit a good pump run life and flexibilities. But worldwide failures information gathered
has no data consistency as well as difficult issue common to all ESP failure-tracking system is
how to treat used equipment [1,2]. Hence run-life measurements standard has several
approaches because no single approach is perfect. yet a complete Life Cycle costs of the
system (cost to purchase install operate, maintain, and dispose of that equipment) not included [3, 4, 5, 6,
7, 14].
On management base, there are two different models - operator with experience who depends
on the alliance between operating companies and service professionals. The system result is
generally depending the feedback knowledge of the operator, supported by the credibility of
the specific service company. At the other side operators without experience is based on
framework agreements where the service companies design, provide and operate the ESP.
This method supposes to be a good start during the learning curve of operators. [8, 9, 10,11,
12] Practically both methods expressed full delegation of ESP management by neglecting the
responsibilities of those who should evaluate the process performance (Reservoir management or
Development engineers).
On technical base, ESP users often underestimate how wells inflow may have developed
when reservoir pressure declines. That the limitation of achieving full potential in pumped
wells is the accurate pressure calculation at the pump intake. Hence precise design calculation
depends on harmony between Bottom Hole Flowing Pressure to Pump Intake Pressure (PIP).
Each pressure differences have a specific pump speed referenced to Hz. Frequency. Yet, none
of the computer programs works the exact Pump Setting Depth in order to obtain pressure
harmony, that’s PSD usually calculated and/or referenced only to avoid Bubble Point
Pressure depth? This can be adjusted through alternating frequency Variable Speed Derive
[13]. The situation is critical in big oil fields where only fixed frequency available.
From the above background we could conclude that Engineering Feedback knowledge to
stakeholders are the most affecting credibility management issue, while Gas Oil Ratio,
optimum PSD are the most affecting design items.
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2. Messla ESP Experience.
To investigate how flexible and economic the current ESP system supposed to be carried
through sequence of events leading up to the observed mode, item and description of failure.
That normally failure mode or item supposed to be inspected to uncover the underlying
human or organizational factors that were influential in the failure, then depth investigation
required.
In Messla the system has no depth failure investigation reports. Only pump performance
observation reports and normal pull/run reports. Initially Messla considered as big oil fields
with 120 wells (see reservoir properties in table 1). Initially PSD fixed at 6000 ft (Slightly dipper than
mid way perfs. to well head) for all wells, the harmony of PIP to BHFP at fixed 50Hz was good
(This provides a sort of reliability to a new system experiment). Earlier average pump run
lives were 2.5 years (Most pump performance mode recognized was up thrust-upper washer’s damages
reported).
Initial RP Current avg. RP BPP
Avg. current
Field WC%
GOR
Scf/bbl
Decline Rate
%/year
WC%
increase
/year
Pressure Rate
decline/year
3950 2350 1340 30 350 5 1.50
20-30
Table (1)-Data according to RED-AGOCO-NOC technical meeting book.
Lately during the last 8 years’ pumps run life decreased to few months (see table2). The
reason of this decreased pump run lives is the decline in reservoir pressure, hence pumps
design and pump performance should be changed accordingly (see table 1). (Pump performance
recognized, low WHP, usually chock back solution applied- no flow to surface, gas lock was the diagnosed
reason, usually gas handler or separator reruns- workover kill fluid usually swabbed manually that ESP cannot
lifted, it takes from 3 days to a week).
Year 2018 2017 2016 2015 2014
Avg. No of wells on production 60 60 60 53 37
ESP. Off Down Hole 27* 38 34 28 16
Table (2) represent ODH numbers during last 5 years. *up to 23-August/ 2018.
Also during this period ESP equipment and accessories stock were not well prepared and
flexible (limited stock). This is due to the complex purchasing progress when it is based on
individual well base as for large field such Messla. Electronic like Vortex and K-45 were used
but there were no analysis reports. Also VSD has tested on some wells without an overall
interpretation reports about optimum future pump PSD for fixed 50Hz.
Therefore, it is important to predict future needs to forecast reservoir uncertainty to select the
right ESP equipment and to prepare stock in advance. Table (3, 4) represent PSD and Total
Dynamic Head calculation required for the next 5, 10 years based on the same design
formulas used in Messla field [12]. Wells were classified in to 3 groups based on PI intervals
as shown in table (3).
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3. Table (3) Represent well groups referenced to the Productivity index’s interval. Then calculated reservoir properties after 5, and 10 years.
Only one well with PI =28 excluded.
From table (3, 4) two choices provided, either to fix the PSD between 5 to 10 years’ targets,
for example 7300 ft. group A, 7200 group B, and 7100 group C. This would avoid gas
problems (Below BPP-Gas devises not required), maintain the stock, and maintain reservoir
uncertainty. The other choice is to keep the existing individual random PSD. This would
complicate the system.
It is important to know that PSD is going to be lowered dipper to avoid gas due to declined
avg. pressure. That would restrict Pump efficiency at fixed 50 Hz. (an extra stages supposed
to back up the existing one to substitute the pressure difference. Hence we recommend VSD
test to improve the calculated extra stages required.
Wells group
P.S.D After
5 yrs.
T.D.H After 5 yrs.
+WHP+tbg
friction
Required
stgs.
P.S.D After
10 yrs.
T.D.H After 10
yrs.+WHP+tbg
friction
Required stgs.
A 7163 4573 388 7449 4922 424
B 7074 4485 290 7385 4858 314
C 6946 4357 147 7279 4753 165
Table (4) represents calculated pump setting depth, total dynamic head required, and stages required. Stages calculate need VSD to confirm
pump performance due to new PSD.
Rate 500 650 1000 1300 2000
Pump type DN450 D725N DN1100 D1400N GN2100
Ft/stg 50Hz. 11.77 16.34 16.12 14.51 28.93
Table (5) stages required are calculated based on most frequent used pumps in Messla field. Red colour represents Group B
Conclusion
In one side, the initial over range rates (up thrust), the lately low pressure wellhead, choke
back solutions, long time duration taking to swab the kill fluid, were mostly indicating low
stages pumping performance. Also the non-flexible ESP stock referred to the individual
purchase orders base. To improve Messla field development, the choice to fixed PSD is
strongly recommended. That would demonstrate in head of time the possible future technical,
warehouse, and management troubleshooting issues.
Recommendation
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Well
groups
IP interval Avg. PI Total
Q
Total L.
grd. 5 Ys
Total L.
grd. 10
Ys
BHSP
5trs.
BHSP
10yrs.
BHFP
5yrs.
BHFP
10yrs.
Datum
A 1-4=29 well 2 500 0.383 0.39 2225 2100 1975 1875 8800
B 5-8=25 well 6.5 1200 0.383 0.39 2225 2100 2025 1915 8800
C 9-16=30 well 12.5 1850 0.383 0.39 2225 2100 2065 1952 8800

4.  Since normal ESPs can handle free gas up to approximately 20% volume
fraction without gas separation or gas handling equipment [9]. Messla
GOR is too low to consider complex design and/or advance equipment. To
confirm that a down whole sample test at several depths is required to
approve how much gas evolved.
 VSD is strongly recommended to determine the extra stages % required to
substitute pressure decline.
 Pumps, motors, cables, and pump inventory should be re-evaluated to
fulfil shortage for next 5 years.
 Purchasing new equipment or replacing old equipment will prepare based
on the new stock shortages.
o Due to the calculated TDH, 3 pumps in tandem or more will be
expected. Tandem should be selected as short as possible.
o Three or more pumps in tandem will provide inventory options to
designer to fulfill shortages using only the 3rd
tandem as the
changeable item. The new inventory should be based on this
arrangement.
o Special strength care should be paid when 3 tandem pump and/or
motors purchase, that shaft limited by-the maximum burst-pressure
rating of the pump housing - the maximum allowed axial load on
the pump’s main thrust bearing.
 Existing cables should be extended for the new PSD requirements’ as the
field not targeted to produce on full wells load, hence No overseas
purchasing would be required.
References:
[1] Challenges of Using Electrical Submersible Pump (ESP) In High Free Gas Applications. Authors,
Ali Suat Bagci (Eclipse Petroleum Technology Ltd.) | Muharrem Murat Kece (Eclipse Petroleum
Technology Ltd.) | Jocsiris Delida Nava Rivero (Eclipse Petroleum Technology Ltd.). DOI
https://doi.org/10.2118/131760MS SPE-131760-MS. Publisher Society of Petroleum Engineers. Source
International Oil and Gas Conference and Exhibition in China, 8-10 June, Beijing, China- Publication
Date 2010
[2] THE IMPORTANCE OF ELECTRICAL SUBMERSIBLE PUMPS (ESPs) IN MAXIMIZING OIL
RECOVERY by Mazen H.Modahi Submitted in partial fulfilment of the requirements for the degree of
Master of Engineering Major Subject: Petroleum Engineering at Dalhousie University Halifax, Nova
Scotia July, 2012
[3] ELECTRICAL SUBMERSIBLE PUMP SURVIVAL ANALYSIS MICHELLE PFLUEGER
Petroleum Engineer, Chevron Corp. & Master’s Degree Candidate Advisor Dr. Jianhua Huang with
help from PHD Candidate Sophia Chen Department of Statistics, Texas A&M, College Station
MARCH 2011
[4] ARTIFICIAL LIFT MANAGEMENT RECOMMENDATIONS AND SUGGESTIONS OF BEST
PRACTICES Clemente-Marcelo Hirschfeldt* Oil Production Consulting & Training, Comodoro
Rivadavia, Argentina Universidad Nacional de la Patagonia San Juan Bosco, Comodoro Rivadavia,
Argentina e-mail: marcelo@oilproduction.net (Received Apr. 04, 2011; Accepted Jun. 07, 2011)
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5. [5] Titel of thesis: Artificial Lift – Electrical Submerged Pump, best practice and future demands within
subsea Applications-Faculty of Science and Technology MASTER’S THESIS-Spring semester, 2010.
Faculty supervisor: Conrad Carstensen, UiS External supervisor: Ole Johan Samdal, Statoil ASA.
[6] Electric Submersible Pumps for Artificial Lift Intelligence John Algeroy Rosharon, Texas, USA for
help in preparation of this article, thanks to Ryan Cox, Rosharon, Texas; Ramez M. Guindi and Grant
Harris, Houston; and Barry Nicholson, Sugar Land, Texas. espWatcher, FloWatcher, MultiPort,
MultiSensor, Phoenix, QUANTUM, RapidSeal and REDA are marks of Schlumberger.
[7]. Vachon G and Furui K: “Production Optimization in ESP Completions with Intelligent Well
Technology by Using Downhole Chokes to Optimize ESP Performance,” paper SPE 93621, presented
at the 14th SPE Middle East Oil and Gas Show and Conference, Bahrain, March 12–15, 2005. 6
[8] Analysis of Influence Factors of Electric Submersible Pump Performance in X Oilfield Ren
Xidong1 , Meng Fanyuan2 , Tian Yuming2 , Du Chunyu2 , Xu Jialiang2 1 (College of Petroleum
Engineering, Northeast Petroleum University, Daqing 163318, China) 2 (College of Petroleum
Engineering, China University of Petroleum (Beijing), Beijing 102249, China).
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[10] Sawatyn S J, Grames K N. The analysis and prediction of Electric Submersible Pump Failures in
the Milne Point Field, Alaska [J]. SPE56663, 2011.
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Wells [J]. SPE63045, 2003.
[11] Challenges of Using Electrical Submersible Pump (ESP) In High Free Gas Applications Article ·
April 2013 with 414 Reads DOI: 10.2118/131760-MS Cite this publication Baker Hughes, a GE
Company Muharrem Murat Kece- Jocsiris Delida Nava -Heriot-Watt University
[12] Gabor Takacs, “Electrical submersible pump manual: design, operations, and maintenance”,
published by Elsevier Inc., May 2009.
[13] Divine, D. L., “A Variable Speed Submersible Pumping System”, Paper SPE 8241 presented at the
54th Annual Fall Technical Conference and Exhibition held in Las Vegas, September 23 – 26, 1979.
[14] C. Jose, K. Frank, 2004, “CFD Analysis of Electric Submersible Pumps (ESP) Handling Two-
Phase Mixtures”, Journal of Energy Resources Technology, 126, pp. 99-104.
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