7/25/2019 SPE-160719-MS (2)_unlocked

1/12

SPE 160719

Assessment of Artificial Lifts for Oil Wells in EgyptM. Ghareeb, Lufkin Industries; W.F. Ellaithy, Arabian Oil; I.F. Zahran, Egyptian General Petroleum

Copyright 2012, Society of Petroleum Engineers

This paper was prepared for presentation at the SPE Annual Technical Conference and Exhibition held in San Antonio, Texas, USA, 8-10 October 2012.

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 have not beenreviewed by the Society of Petroleum Engineers and are subject to correction by the author(s). The material does not necessarily reflect any position of the Society of Petroleum Engineers, itsofficers, or members. Electronic reproduction, distribution, or storage of any part of this paper without the written consent of the Society of Petroleum Engineers is prohibited. Permission toreproduce 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 SPE copyright.

Abstract

One of the challenges facing the Egyptian oil industry is to increase production and maximize reserves especiallyin mature and marginal fields.

The fast and continuous development in artificial l ift tec hnology plays a role in solving these problems. Recentimprovements in technology, automation and metallurgy have reduced lifting costs through system componentsthat resist hostile environments, optimize power usage, and improve reliability allowing profitable production frompreviously uneconomic fields or wells.

Since the oil industry first emerged in Egypt, over 200 oil and gas fields have come on-stream. Natural producingwells represent less than 9% of this total; other wells are lifted artificially.

This paper will present the history, present day, and the future application of artificial lift systems in Egyptian oilfields, covering the main problems encountered in the operation of each single system of artificial lift including theactions taken to overcome or eliminate these problems. Special emphasis will be given to marginal and mature oilfields because of the economical limitations accompanied with development costs.

Introduction

The oil industry in Egypt first began in 1910 and has since grown to cover most regions of the country as shown inFigure 1. There are natural producing fields and other fields that produce artificially via different types of artificial liftbased on well location and producing condition. Beam pumping (BP) ,Electrical submersible pumping (ESP), andgas lift are the most common artificial lift systems applied in Egyptian fields. Hydraulic and progressing cavitypumping systems are also used. Each is suited to certain lifting requirements and operational objectives, but thereis an overlap between each system depending on subsurface conditions, fluid types, required rates, well inclinationangles, depths, and completion configurations.

The usual practice of selecting the suitable lift system for new wells based on review of the nearby location givesbetter well performance for a longer period with low operating cost during well life. Once a lifting system has beenselected, it is expensive to change to another system, especially if the well is located offshore.

7/25/2019 SPE-160719-MS (2)_unlocked

2/12

2 SPE 160719

Figure (1) Location map for the Egyptian oil fields.

Figure 2 shows the distribution of hydrocarbon producing wells and the types of production systems for these wellsin Egypt. Generally, the majority of offshore wells are on continuous gas lift or ESP. Gupco and SUCO use gas liftas their preferred system in offshore wells due to the abundance of gas and low operating cost. Petrobel has usedESPs in Sinai and on offshore fields in the Gulf of Suez. The company also uses rod pumping systems in some ofits onshore wells. Agiba Petroleum Co. utilizes a variety of pumps on its fields in the Western Desert.

A: Total Number of wells (onshore and offshore) B: Onshore wells only

Figure (2) Total Egypt artificial lift installation by system type

The Electrical Submersible Pumping System

ESP systems have the highest producing rate among all artificial lift techniques. Accurate well data is required toselect the right pump size that will operate efficiently under its operating limit. The economics of this system start todecline for depleted wells with a rate under 1,000 barrels of fluid per day (BFPD). It is a good choice for higherproduction rate wells.

Any type of downhole failure requires wells to be worked-over, which is both risky and costly. Workover evaluationshave identified two main types of risk: cables at risk of damage during pulling and/or running of hole (POOH), andthe formation are at risk of damage by well-killing fluid, especially in depleted reservoirs.

Operating cost in depleted reservoirs is high due to frequent workover on downhole equipment failures, since mostof the systems capital costs lie in downhole equipment. As the equipment is consumable with operations, thesystems salvage value is low. For these reasons, several companies such as Khalda and Qarun switched lowerproducing wells, which show low profits (minimum capability to deplete the wells and high operating costs), to otherlifting systems.

Another problem encountered is the p lugging of pump intake with sand and/or s cale, especially wells in theWestern Desert area. This problem causes well production to d ecline and requires frequent intake cleaningperformed by injecting fluid from tubing after shutting-in the well. This does not always succeed and in most casesthe well does not return to its original production level.

7/25/2019 SPE-160719-MS (2)_unlocked

3/12

SPE 160719 3

From the daily operation reports received by EGPC from all the operation companies, ESPs recorded short runninglives in wells with variable productivity. For example, Agiba installed ESPs in higher rate wells instead of using rodpumps and in less than two years most of these wells were put back on the old system because the ESPs were notas flexible as Beam pumping system in c ase of well pr oductivity change. Consequently Agiba installed theavailable ESPs only in wells that have stable production (well productivity) over a long period. Qarun and mostother Petroleum companies are applying the same concept. For such wells, all kinds of artificial lift will work withhigh efficiency.

ESP Problems and Their Analysis

Frequent motor and cable failures, pump plugging and corrosion/erosion of the ESP string are the main problemsthat badly affected the performance of the ESP systems for most of the operators. Figure 3 shows the distributionof these problems. The major operators such as Petrobel, Khalda, Qarun has been takes some remedial actionswith the main ESP suppliers in Egypt and improved the systems running lives.

The analysis show that, most of the cable failures are due to:

Loosening of the cable insulation (Not molded to the conductors):

Loss of insulation elasticity

Some mechanical damage (rubbing, squeezing) of the cable

Figure (3) ESP Failure categories

The review of the production history of the wells which have frequent cable failures showed that some of thesewells were producing with production rates lower than the pump optimum rate and consequently the p umps inthese wells were running at low efficiency (about 20%).

Pump intake plugging are also one the major ESP problems in most fields. The main causes of this problem aredue to scale and some for low producer wells with high paraffin content. Also sand, debris and/or other foreignmaterial found to be one of the plugging causes. As a result of this plugged problem, the problematic wells werefrequently shut-in (almost once a month) due to no flow. In addition to defer in production, high expenses wereincurred to replace the plugged pumps.

The prevention of solid materials is usually achieved by installing a screen on the pump intake. In several fields

screens of mesh size 13-18 are found to be suitable to eliminate plugging problems. In addition to installation ofscreens on the pump intakes, the well bores are sufficiently cleaned before installing the pump.

For the scale problems Chemical inhibition usually achieved by one of the following techniques:

Continuous downhole injection of scale inhibitor and paraffin solvent at the pump intake.

Batch treatment whenever needed. It was found that batch treatment would be an ec onomic. In some fields, thistechnique is applied via two ways. The first is recycling (every 2 - 8 weeks or whenever needed) all or some of thewell production (treated with scale and corrosion inhibitors) into the well annulus.

7/25/2019 SPE-160719-MS (2)_unlocked

4/12

4 SPE 160719

Regarding the corrosion problems, we noticed that most operators are not good in planning for the future change inthe well fluids. They are considered well producing fluids as sweet fluids. Therefore, standard tubing and ESPequipment of carbon steel base material are usually selected with coated ESP b ottom hole a ssembly. Also,sacrificial anodes are using in most of the ESP string (below motor).

Beam Pumping System

Beam pumps are the oldest lifting system and the most commonly used in Egypt. The system is using for lifting

moderate rate wells from intermediate depths. Figures 4 show the wells using Beam rod lift systems. Figure 4-Awells grouped based on pumping depth and Figure 4-B wells grouped based on total fluid produced per day .

Figure (4-A) Figure 4-B .

Figures 4 show the wells using Beam rod lift systems.

Introducing beam units with different geometry such as front-mounted or larger sizes, in addition to rods with highload capability such as the N97, allows for using larger subsurface pumps. Consequently, several companies haveapplied the beam pumping system to produce relatively high rate wells from moderate depth. For example, Agibaproduced almost 1,000 BFPD from 6,500 feet using Lufkin Mark II, size 912D-365-144 surface driving with ultrahigh slip (UHS) motors with 87 high tensile rod string and 2.5 insert cup type subsurface pump. Bapetco is alsoproducing quite high volumes from + 7,000 feet using Lufkin MII 912D-427-192.

Moreover, improvement of rods and subsurface pumps metallurgy allow the engineer to run the system for wellsproducing with corrosive fluids. GPC, as an example, improved wells producing with H2S running lives after usingsuitable materials for the subsurface pump. This allowed the company to increase Ras Gharib field production. Inaddition, the availability of well servicing equipment, spare parts, and highly qualified services companies with fulltechnical support makes the beam pumping system the most visible means of artificial lifting for Egyptian oil wells.In the last couple of years several companies switched their lifting systems (ESP, Jet and PCP) to beam pumpingsystem as shown by the following case histories:

Eastern Desert

Petrodara is one of the Eastern desert companies. Currently producing + 10,000 BOPD fo rm marginal fieldproduces heavy crude oil. At the beginning, all the wells were run using PCP. After a couple of years, the systemproved to be uneconomical. Therefore, the company tested beam pumping as a replacement for PCP. The reasonbehind this was the high operating cost of PCP. Each time the system was pulled due to a subsurface problem at

least 50% of the subsurface pump components had to be rep laced. The PCP subsurface pump represents onaverage 50% of the total system capital cost. In addition, the spare parts have to be imported. This can lead to stopwell quite a long time and as a result stocking of such an expensive spare complete pump is necessary. This, inaddition to some other operating and monitoring problems, pressed the company to change their philosophy anduse the beam pumping system as a lifting system.

Western Desert

Khalda and Q arun petroleum companies are two major oil pr oducers in the western desert of Egypt. Bothcompanies are starting their production system by using ESP as the main artificial lifting system. The system was

7/25/2019 SPE-160719-MS (2)_unlocked

5/12

SPE 160719 5

good at the i nitial life of the reservoirs, but when reservoir pressure declined, the system started to suffer fromfrequent equipment failure, especially motor, cable, and seal section. Some of the wells were shut-in due to highoperating costs. This was due to the limited flexibility of ESPs to cope with a decline in well productivity. In addition,any subsurface problem requires workover of the well. Replacement of subsurface equipment is costly.

Both Khalda and Qarun have been switched ESP w ells producing less than 300 BFPD to beam p umping.Converted wells have shown good performance. This lead to ex pand the application limits for beam pumpingsystem and w ell producing 600 BFPD and less sw itched BPS . According to EGPC and Khalda reports the

average run lives of the BPS during 2011 was 19 months with wells running over 7 y ears without any surfaceand/or downhole failure for both companies.

Agiba, Western Desert

Agiba has had 26 years experience with beam pumping systems. Agiba is the first company in the area used inyear 1986 Mark II units (Lufkin MII 912-365-144) with ultra high slip motors and 86 N97 rods to produce 500 -600BFPD form depth 5000 ft. Agiba reports show low running lives of the rods and pumps compare to Khalda andQarun. Most of the failures were a result of the rod parting together with downhole pump problems, which affectedproduction and lead to rising lifting costs (cost/barrel). Through continuous monitoring and analysis, it wasdiscovered that the systems performance had been affected by lack of monitoring; the companys crew had beenin charge of handling all the field production operations and not focused in the rod pumping systems (+240 wells).The companys technicians and enginee rs demonstrated a high work commitment, but lack of optimization &automation tools plus the suitable handling tools hampered their efforts.

Sucker rod system failure analysis

Upon analysis of the western and eastern desert fields condition and well operational parameters, it found that thefollowing general problems are quite common and negatively impact the life of wells and their average annualproduction:

Over size equipment and running parameters( fluid and /or gas poundings)

Corrosion

Sand production

Lack of automation and monitoring in some fields

Poor system design. Several companies are still depends on the personal experience and best practice

Down hole frictions (rod-tubing and plunger-barrel frictions)

According to the last two years (2010 -2011) surveys and reports received by EGPC from all the oil companies andas shown by Figure 5 about 52 % of the wells problems occurs in the subsurface pumps. The second major partsin failures are come from the rods. Rod failures represent 43 % (34 % rod parted and 9 % coupling unscrew). Thetubing failures represent 5% of the total wells problems. Even with this low percentage, tubing failure consider oneof the most costly problems. This is because restoring wells to normal production require pulling the completionstring. This is will require workover rig and it usually couple of days operations in case of the rig is available in thefields. In most case especially for medium to small producing companies the wells stop for quite long time waitingfor rig.

7/25/2019 SPE-160719-MS (2)_unlocked

6/12

6 SPE 160719

Figure (5) Beam pumping system failure modes

While all failure modes cannot be completely and adequately covered in this paper, some common failures andtheir possible cause(s) follow:

Rod String Failures: All failures in the sucker rod string are found to be fatigue failures. Failure in the rod stringare result from improp er make-up, corrosive fluid i nducing corrosion pits, tubing slap/rod string buckling from

improper rod string design, fluid pound, tagging of the pump, unanchored or improperly anchored tubing. Note thatpounding fluid not only causes rod compression and buckling but can also burst pump barrels and damage pumpvalves. Performing failure analyses and tracking failures helps several operators correct problems with the rodstring design or operating conditions and determine if a corrosion inhibition program should be implemented ormore aggressively pursued. Sucker rod handling along with the fluid pounding found to be the major reasons forthe majority of rod failures.

Tubing failures: several studies has been made and came with the conclusion that all the reported tubing failure isa longitudinal crack with an average length of 10 ft. almost in all the reported tubing cracks found to be always inthe lower part of tubing in th e area form t he setting depth to about 500 ft hi gher this problem found to b econcentrated in the company using the 1 rod with full size coupling as sinker bar.

Agiba did a very good study and they concluded that, for the vertical wells, such problem is being created due toone or combination of the following reasons:

Tubing buckling due to im proper tension considered while anchor catcher or packer setting. (Buckling exists bynature in the lower part of tubing string). Keeping the required pre-calculated tension in the tubing when usingtubing hanger to hang tubing at surface found to be very difficult and usually results in buckling lower part of thetubing..

Over 90 % of tubing cracks found to be occur in wells producing with high water cut. Free water production usuallyincrease friction coefficient between rod coupling and tubing. This is results of poor lubrication and excessive wallroughness due to pitting corrosion, represents the main reason.

Sucker rod buckling due to insufficient sinker bar weight and/ or down hole friction due to low plunger fit (-4)

Fluid pounding.

Several Best Practices were developed to reduce those causes of failures. But unfortunately the failure frequency

has not been reduced to the accepted results compare to the neighbor companies such as Khalda and Qarun.Early 2011 Agiba requested form Lufkin optimization team to study the problems and jointly with Agiba engineeringand production engineers they come out with the following conclusion and corrective actions which show very goodresults for the pilot test wells at Agiba and it is applied by Khalda and Qarun:

Redesign the rod string configuration using SROD software

Replace the 1 sinker bare ( 18 Joints) with 1.5 heavy weight bar with 7/8 threads

Replace the conventional tubing hunger with KTH flange

7/25/2019 SPE-160719-MS (2)_unlocked

7/12

SPE 160719 7

Use 5 ft stabilize bar just above the down hole pump

Open plunger fit to be not less than 0.005

Optimize well parameters to minimize the fluid pounding

Surface units was slowed to minimize number of c ycles (strokes) per minute with increasing the strokelength and to produce the same volume per day

Progressing Cavity Pumping (PCP)

PCP is using since not long time in Egypt for the Egyptian market. Agiba is the first company in Egypt to implementthis system. The system has been introduced in 1997 as a pilot test on a no-cure no -pay basis. Currently, areasonable number of wells are running with PCP systems in Egyptian oil fields; some use insert pumps andothers tubing pumps.

50 Wells have been produced with PCPs with average run life 3-4 months during 2009 where PCP failure duringthe Year 2009 Cost the company $1000,000.

Installing the down hole gauge with automatically controlling the pump speed, increasing the pump run life from 3months to more than two years.

The old ultra strength sucker rod has been replaced with new rod made from nickel -chromiummolybdenum alloywhich has better resistance to corrosive environment.

Changing the elastomer type from soft Buna to 100c/HNBR increasing the pump capability to work under High H2Senvironment and high temperature up to 100 C-140C.

Limitations of the PCP system are:

- It requires certain pump intake pressures.

This means the pump off condition cannot be reached, and consequently pumping at maximum well potential isimpossible.

- It has very low salvage value, where most of the capital investment is for downhole equipment.

- Since the downhole pump represents an average of 50% of the total system cost, any failure will require at leastreplacing either rotor or stator, which means that minimum repair costs will not be less than 25% of total capitalcost. Therefore, it has a relatively high operating cost.

- It is sensitive to light crude oil (high aromatics).

The PCP system only applied in Egypt for heavy crude. Most of the systems are using in the eastern desert ofEgypt. Scimitar and Petrodara are the main users.

Gas Lift System

Gas lift is the most common system used in offshore fields in Egypt. The system is suitable for such fields due tothe limited spacing on the platform (one compressor can run the platform wells). In addition, it is suitable for hightemperature conditions, high gas/ oil ratio wells, and is compatible with sand production.

For the above reasons, gas lift is the preferred technique for artificial li ft in offshore fields in the Gulf of Suez(GUPCO, SUCO, PETROZEIT and Agiba). All GUPCO fields in the Gulf of Suez use gas lift since 1965 and up tillnow. Also SUCO used gas lift in the two main fields, RAS BUDRAN and ZEIT BAY fiel ds since 1985. Gas liftsystem is also applied in s ome fields in the Western Desert in Egypt (Abu El Gharadik, BAPETCO).The mainproblem currently encountered is increasing the water cut with production and consequently drop in the volume ofthe produced gas. As per figure 6 about 70 % of the well service are down hole Valves failure.

7/25/2019 SPE-160719-MS (2)_unlocked

8/12

8 SPE 160719

Figure (6) Gas lift Failures categories

Jet Pumping System

Currently 4% of lifted wells are producing using jet pumps. The high workover cost of this pump usually entices theoperator to switch to the beam pump system, as in the case of some Western Desert fields operated by Agiba andKhalda. The disadvantages of this pump are:

- The tubing and casing are occupied; one for production fluid and the other for power fluid. This makes it difficult tomonitor bottomhole pressure from the surface compared with other forms of artificial li ft.

- The pump system uses high velocity mixing devices causing the flow to be turbulent.

- Friction within the pump leads to lower horsepower efficiencies than can be achieved with positive-displacementpumps. This often leads to higher surface horsepower requirements.

- Jet pumps are susceptible to cavitations at the entrance of the throat at low pump intake pressures; this must beconsidered in designing calculations.

- In most cases, the system requires high power fluid pressure at the surface (+2,500 psi). This is a safety hazard.

For these reasons jet pump systems are not the preferred permanent lifting system in Egyptian oil fields.

Automation and Optimization History

In the 2001, a program to increase production in Khalda fields was based on converting ESP low producer wells tosucker rod systems. Managing wells production and system running lives became a priority from the day one andpump-off controllers (POCs) were installed for the first time in Egypt. Between 2001 and 2011, well failures(failures per well per year) at Khalda fields, recorded to be the minimum rate compare to other companies in thesame area. Starting 2008 other medium to small producer copied the same automation system using by Khaldaand gain the also good system performance. One of the major oil producer in Egypt ( Agiba) preferred some othermonitoring systems and they are depend on the conventional dynamometer and fluid level survey with threemonths interval between each test. Also they just install a SCADA system to monitor well head pressure andtemperature to watch daily well production behavior based on the change of the well head temperature. Wherethey are using the equation generated by this paper author (M. Ghareeb) to estimate the well production rate formthe reading of the well head temperature.

For the PCP system in Egypt, well automation is limited and the downhole equipment running life is very low.

Scimitar is one of the ma jor companies for PCP application in Egypt. It is running 200 heavy oil producer wellsunder steam injection system. 25 % of those wells are equipped with PCP, 73 BP and 2 % ESP systems. Initiallydue to lack of well automation and continues monitoring wells running lives are very short. It is in average 3months. Due to repeated PCP failures, Zenith downhole gauges have been installed in selected wells. Accordinglypump run life has been increased from 3 months to more than 2 years till now by automatically controlling thepump speed (RPM) via variable frequency drive versus the pump intake pressure. Where, be fore installing thegauges all the wells are running at 50 HZ. This is due to the misleading of the fluid level (fluid over the pump). Theyare depends on the traditional acoustical fluid level measurements. In case like scimitar well conditions producingheavy crude oil with low gas/liquid ratio usually the fluid in the annulus is foamy fluid. The foamy fluid in the

70%

10%

10%

10%

0 0.1 0.2 0.3 0.4 0.5 0.6 0.7 0.8

valve failure

valve plug.

gas ck. plug.

gas comp.

7/25/2019 SPE-160719-MS (2)_unlocked

9/12

SPE 160719 9

annulus gives them an erroneous fluid. This led the pumps to run dry in mo st cases and cause pump failureespecially the elastomer.

Conclusions and recommendations

Although the strategies to develop oil fields may vary a great deal based on their maturity or th e corporatephilosophy regarding the de velopment of a field, artificial li ft sys tem management should be taken on with astrategic, integrated vision in accordance with the development of a field.

Monitoring and control are very important for increasing equipment lifetime. therefore well equipped with theautomation systems shown a good performance and equipment longer lives compare wells running withoutautomation

All the reports and findings showed that 80% of all tubing failures for beam pumping system occurred in thebottom 1/8 of the tubing string where buckling of the rod string most often occurs

Working closely with the manufacturer and/or the manufacturers representative is very helpful in determining if theproper pump is used based of fluid characteristics, water-cut of the well or abrasives in the produced fluid.

Pounding fluid is one of the major problem causes for beam pumping systems

Failure analysis and tracking failures are the keys to determining appropriate corrective action to be taken.Cookbooking completions and equipment installations should be avoided and each well should be looked at on

an individual basis before equipment installation decisions are made. Corrective action should be taken only afterthoroughly analyzing the root cause of the equipment failure. To more quickly identify potential problems, real timemonitoring should be seriously considered, as early problem detection and avoidance will result in longer run lifefor the entire pumping system and early payout for well monitors cost.

Even though the sucker rod is an old method of artificial lift but state of the art technology still participate in theoperation of the sucker rod well. It is important to ha ve a controller at each well, whether it has high or lowproduction rate, in o rder to protect the investment made in th e downhole and surface equipment as well ascontinuous monitoring and analysis of well data.

Acknowledgement

The authors want to thank the management of EGPC and operating companies in Egypt for their support and

encouragement of the work presented in this paper.

References

1. Ghareeb M., et al: Beam Pumping System Efficiency Improvement in Agiba Western DesertFields, paper presented at Fall 2005Beam Pumping System Workshop, Houston, Texas, USA, October 2005.

2. Nael Sadek, et al: The Value of Automation in Khalda Sucker Rod Wells paper presented at the Third Middle East Artificial LiftForum, Muscat, Oman, September 27-28, 2005.

3. Ghareeb, M.: Sucker Rod: Efficiency Improvement in Meleiha Field, paper published and presented at the 1st Arpo Convention,Milan, Italy, November 1995.

4. Bucaram, S. M.: Managing of Artificial Lift Systems, JPT (April 1994).

5. Bucaram, S. M., and Hein N. W.: Recommendation and Comparisons for Artificial Lift Methods Selection, JPT (Dec. 1993).

6. Clegg, J. D.: High Rate Artificial Lift, SPE 17638.

7. Ghareeb, M., and Pretto L.: Artificial Lift Optimization in Mature and Marginal Fields, 13th EGPC Petroleum Exploration andProduction Conference, Cairo, Egypt, November 1996.

8. Eloufie, M., and Ahmed E. M.: Successful Conversion of Hydraulic Pumping Wells into Gas Lift, 12th EGPC PetroleumExploration and Production Conference, Cairo, Egypt, November 1994.

7/25/2019 SPE-160719-MS (2)_unlocked

10/12

10 SPE 160719

9. Brown, K. E.: The Technology of Artificial Lift Methods, Petroleum Publishing Co., Tulsa, OK (1980) 2a, 3, 4.

10. EGPC Production Reports.

11. Agiba sucker rod system evaluation study, 2004

12. Sucker Rod Efficiency Improvement In Western Desert Fields, SPE Paper in SPE TTW in Egypt, May 2004

13. SAM Well Manager User Manual, Lufkin Automation, Lufkin Ind.

14. Khalda sucker rod database, 2012

15. Apache Corporation Website http://www.apachecorp.com/world/egypt.htm

7/25/2019 SPE-160719-MS (2)_unlocked

11/12

SPE Number 11

7/25/2019 SPE-160719-MS (2)_unlocked

12/12

12 SPE 160719-ppNumber