Copyright 2007, Society of Petroleum Engineers This paper was prepared for presentation at the 2007 SPE Latin American and Caribbean Petroleum Engineering Conference held in Buenos Aires, Argentina, 15–18 April 2007. 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, Texas 75083-3836 U.S.A., fax 01-972-952-9435.

Abstract

The Golfo San Jorge basin, located in the central Patagonia, is the oldest productive basin of Argentina, where the first economic discovery took place in 1907, in Comodoro Rivadavia.

With 11,680 active oil wells, is the first oil producer basin of Argentina producing 258,549 bpd of oil and 2.56 MM bpd of water. The main characteristics of the basin are:

- Faults and sand stone lens - HWOR - Increasing fluid flow rate per well - Complex fluids: corrosive, heavy oil, gas, sand and

scale - Multiphase fluids - Multilayer reservoir: from 1.800 to 9000 feet

In this context, the selection, operation and optimization of

the different Artificial Lift Systems (ALS) plays an important role for following the development of the basin.

This paper describes the best practices, experiences and trends, using ALS as Progressing Cavity Pump(PCP), Electric Submersible Pump(ESP) and Sucker Rod Pumping(SRP); and a basic description about Gas Lift, Plunger Lift and Hydraulic jet Pumping experiences.

Information as pump depth, flow rates, operational conditions, surface and sub-surface installations description, technical limits, failures statistic and new technologies from more than 9,000 active wells from different oilfields were collected and analyzed.

As result of this overview, an ALS reference guide was completed with parameters and benchmarking indicators; and some important conclusions appear.

Complementary information will be presented in the Appendix (Fig-A1, A2, Table-A1, etc)

Introduction

The East-West trending Golfo San Jorge basin is the oldest and most prolific oil basin of Argentina It covers 28,000 M Acre, with 1,127 MMbo (Dec-05) of OOIP and is located in the central Patagonia. (Fig-A1)

The first commercial oil discovery took place in 1907 and

since then close to 2,900 MMBOE were extracted. Located in the central part of Patagonia Terrane, it is an intracratonic extensional basin. During late Jurassic-early Cretaceous times, the extension related to the Gondwana break-up generated many isolated small half-graben basins, with a NW-SE structural trend. Later, a new extensional-transtensional stress field originated a WNW-ESE trending, and reduced extensional deformation continued until the Oligocene.

The basin is essentially asymmetric; in the eastern section the dominant extensional faults are on the northern flank with the southern flanks being a less faulted, flexural type margin. In contrast, the western section is asymmetric but its major faults are on the southern flank, being the northern flank a flexural margin. The central section of the San Jorge basin is dominated by NW and NNW trending extensional faults that were reactivated by compression in Tertiary times.

The basin produces 258,549 bpd of oil (44 % of the oil

production of Argentina), and 2.56 MM bdp of water (91%) at November 2006. Close to 2.6 MMbpd of water are injected in 2,400 wells in water flooding projects, therefore 41% of the oil is produced from this method. (Fig-A2)

Close to 97 % of the wells were completed with 5½”

casing, and depending on the companies, new wells are completed with 7” casing. Vertical wells are the most common and directional wells are drilled in some projects (water flooding, parallel to faults)

Artificial Lift System (ALS) in Golfo San Jorge

From the begining of the activity in Golfo San Jorge Basin, 100 years ago, several ALS have been used in order to produce the oil from each well.

The basin offers different conditions depending the mature state of the oilfields: high water percentage, high and low flow rate, free gas and in solution, heay and light oil, flowing wells and high GOR reservoirs .

SPE 108054

Artificial-Lift Systems Overview and Evolution in a Mature Basin: Case Study of Golfo San Jorge Marcelo Hirschfeldt, Paulino Martinez, Fernando Distel. Universidad Nacional de la Patagonia San Juan Bosco. Argentina

2 SPE 108054

At the present time, ALS as SRP, PCP and ESP are the most popular systems used for producing 98 % of the total fluid of the basin. And in smaller quantity, wells produced by hydraulic jet pump, pluger and gas lift.

The growing reservoir depth and flow rate of fluid per well, present a permanent challenger for the different ALS and specialist.

In this context, the selection, operation and optimization of the different systems plays one of the most important roles for following the basin development.

One of the common factors in all oil wells, is the casing diameter, where 5½” diameter forces to use 2⅞” tubing and 1” sucker rod.

For this reason during the last years, one of the main targets of the companies and engineers has been to increase the technical limit and life of each system. Distribution and evolution

The number of active oil wells is 11,887 with the follow distribution:

Others: Hydraulic Jet pump, Plunger and Gas Lift (nov.06) The Fig.A3 shows the evolution of the most important

artificial lift systems from 1999. During the last eight years, the number of wells per system

it has grown in function of the advance of the technology and of the new requirements of the basin.

PCP is the system that increased the number 237 % from 1999. One of the reasons for this important growth is the new development in materials as elastomers, sucker rods, pumps design and surface instalations. And in the other hand, the field engineers and companies began to study the system and to try new challenges.

The second is the ESP with 224 %, where the growing reservoirs depth and flow rate in water flooding projects forced to the system to reach demanding production forecast

One of the performance indicators we use to measure the failure index of the system is the Pulling Jobs per Well per Year. Failure index (FI)=(Pull. Jobs per month /num. of wells) x 12 Sucker rod pumping (SRP)

SRP is the oldest artificial lift in the basin and the most popular with 9,141 units running, In spite of this, the growth of the wells from 1999 was 18%, the minimum of the all systems, but this continues being a flexible alternative with a wide operation range.

The Fig.3 shows a cross-plot depth vs. flow rate with information from 7,663 active wells.

The cross plot (Fig.3) shows a range of depth from 1,000 ft

to 10,000 ft for low flow rates. This range of applications falls as the flow rate requirement increases, representing the mechanical limit of the system (sucker rods and pumping units). Best Practices and new development.

The most important developments and best practices have been applied for increasing the mechanical limit of the system, the cicle of life and to improve the fluid handling, due to the increment of the flow rate and to optimize the production..

Pumping units. Common pumping units are: the conventional, Mark II and air balance. Around 45 % of the units are Mark II, being the biggest units 912,000 and 1,280,000 lbxft of torque and only one experience with a MII-1824-427-216, the biggest pumping units of Argentina.

Long Stroke Pumping Units. As the depths increase, as well as the SPM (stroke per minutes) and stroke length, and the effective down hole stroke and volumetric efficiency falls.

Slower speeds and longer strokes result in more complete pump fillage and lower dynamic loading. (see the pumping unit model Fig-A4). This is the main characteristic of this unit.

Dynamometer cards run on these applications are similar to a theoretically perfect card. An example of a dynamometer card is showed in Fig-A5.

The next examples represent two real experiences in Golfo

San Jorge Basin from seventeen (17) wells runing:

System wells %SRP 9,141 76.9PCP 1,469 12.4ESP 1,234 10.4Others 43 0.3

Table 1. Artificial lift distribution

Fig.3 – Cross plot pump depth vs flow rate (SRP) from 7,663 wells

Table 2. Long stroke pumping units instalations

Well # 1 Well # 2Setting depth pump - ft 7,850 11,230Pump diameter - in TH-2¼” TH-1 ¾”Pumping UnitSucker rod stringStroke - inSPM 3.9 3.5Fluid Flow rate-bpd 870 125

R-900-360-2891”-7/8"-1 5/8” Grade D

288

SPE 108054 3

Hydraulic Pumping Units. A few experiences with hydraulic pumping units promise a great development of these due to flexibility for managing the speed and stroke length. Fig-A6. Sucker rod string. Grade D ¾”, ⅞” and 1” are the most common, and some experiences with high strength rods. It´s usual to use sinker bars for improving the performance of the rod loading.

Oversize pin sucker rod. This modification was created for

increasing the limit of the grade D sucker rod string in demanding condition of depth and flow rate and reinforcing the pin of the rod.

The sizes developed are: 3/4 “ SR(sucker rod) with ⅞” pin and ⅞” SR with 1” pin, increasing the capability of the system to 15-20% (more flow rate or deepest setting pump).

Pumps. Rod pumps from 1½” to 2” in 2⅞” tubing and tubing pumps from 2¼” to 3¼” (in 5½” casing) are used. (See for details Fig-A7)

Hold downs (pumps anchors). Can be mechanical or cup type. In deep wells bottom and top anchors are used for improving the locking.

Ring plunger. They are intended for use when metal

plungers are unable to produce the well due to sticking or galling when aggressive sands or large percentages of particulates are being pumped. One of the example is the use of fourteen (40) soft rings in shallow wells (less than 3,000 ft), high flow rate, high water % and sand. Other practice is the use the convination between soft and hard rings.

Self lubricated plunger. This plunger has two seal rings at

the extremes of the plunger and it is filled with a silicon fluid between these rings and creating 100% of staunchness between plunger and barrel, ideal for producing fluids with sand.

Ring valve or “sand valve” on the valve rod of a rod pump

prevent the sand settling between the barrel and the plunger during downtime, ensure very efficient pumping operations in gassy wells.

Two Stage Hollow Valve Rod Pump. It is a rugged pump

which overcomes most gas locking conditions and has the ability to produce a moderate quantity of sand or other particulates. The secret to the success of the Two Stage Hollow Valve Rod Pump is its modified upper compression chamber

Guided valve. Is composes of a hemisphere, penetrated by

a stem which projects vertically above and below. This component is called the valve plunger. The stem guide above and below the valve plunger is manufactured with a single cross member containing an aperture for the stem.

The guided valve plunger eliminates the inherent problem of violent uncontrolled contact of the ball's multi-surface

sealing are with the valve chamber, thus eliminating irreversible damage to it and the chamber. Control and monitoring. More than 600 Intelligent Well Controllers (IWC) has been installed in pumping units in Cerro Dragón Oilfield (Pan American Energy). These devices are connected to RTU that collects and transmit real time information as: dynamometric cards, motor, power bands, gearbox and production pipe line. The information is recorded and processed for managing the system.

Failures analysis.

Analyzing information from 6,000 wells the average FI is 0.4 -0.7. Some factors are responsible for the amplitude and variability of this index:

- The range of depth reservoirs and its characteristics present different fluids and problems(sand, scale, heavy oil, corrosion, temperature)

- Different criteria for inspecting and selecting materials

- The mature sate of the basin (flow rate, water %) The most common failures are: - Sucker rod breaks (pin fatigue is the most common) - Sticking or galling of a metal plunger in the barrel - Tubing wear

Progressing Cavity Pump (PCP) The application of Progressing Cavity Pumps for artificial

lifting in Golfo San Jorge Basin is still new compared to other technologies, but is the second largest systems with 1,469 wells and a growth from 436 PCP´s since 1999.

The technology is advancing rapidly and that, combined with new techniques which are learned empirically, continually expands the range of applications.

The smallest investment, compared with other systems, is one of the reasons of this important growth.

Although in their beginnings, the PCP was used to produce wells with viscous fluids and high contents of solids, the use in high flow rate conditions has been growing every day.

Fig.4 shows a cross-plot depth vs. flow rate with

information from 1,175 active wells.

0

2,000

4,000

6,000

8,000

10,000

12,000

0 1,000 2,000 3,000 4,000

flow rate - bpd

pum

p de

pth

- ft A

Fig.4 – Cross plot pump depth vs flow rate (PCP) from 1,175 wells

B

4 SPE 108054

The zone A in the Fig.4 shows a low flow rate area where the maximum is 300 bpd and a depth range is since 1,800 ft to 6,000 ft. This area also represents the beginnings of the system in the basin, when the pumps were selected only for low flow rate wells.

In the zone B, the depth average is 3,000 ft and a great flow rate amplitude. This describe the important applications of the system in sallow reservoir produced by secondary recovery (water flooding) where in most of the cases the use of the same model of pump let to produce from 250 to 1,200 bpd.

Best Practices and new developments The best practices and technologies have been directed to increase the run life and the limit of the system. We can mention some practices:

- To select the best rotor and stator combination - High flow rate pumps for 5½” casing - Increase the torque limit of the rod string - Rod string and Tubing wear prevention - Down hole and surface, control and monitoring. Drive heads. Direct and right angle are the two type of

models used in the basin. (Fig-A7) Electric prime mover is the common installation and IC

motors with right angle drives in remote areas. Hydraulic Backspin Control Device. The original drive

heads were designed for small PCP’s in heavy oil service, but as PCP’S increased in capacity, the potentially hazardous incidents have been increased. Friction Brake with hydraulic pump is used in drive head where the hydraulic horsepower is a critical factor. When the rods backspin, the hydraulic motor at the wellhead will force the hydraulic fluid to flow backwards through the system brake and activates the calipers for griping the disk. (Fig-A8)

Pumps. Tubular single lobe pumps are used made of NBR (acrylonitrile-butadiene rubber) and HNBR (Hydrogenated acrylonitrile butadiene rubber) elastomers. The temperature limit for NBR elastomer is 195 ºF and for HNBR 260 ºF (information from the manufactures)

An small quantity of insert pump for 2 ⅞” tubing are running but it´s not a common use.

High flow rate pumps for 5½” casing has been the last trends, where the only variable for increasing the volumetric constant of the pump was to increase the rotor pitch length. Example of high-flow rate single lobe pump

Rotor pitch length: 7.8” (200 mm) Flow rate: 490 bpd @ 100 RPM Max lift (100%): 6,500 ft Estimated pump length 45 ft

Past experiences with 2:3 multilobe pumps were not

satisfactory. Models as 415-4800 (415 bpd@100 RPM- 4,800 ft of lift) were operated over 350 RPM and several problems appeared, as hysteresis, high vibrations, tubing and sucker rod failures.

Suker rods. The standard sucker rods used are 1” and ⅞” grade D, and some experiences with high strength rods.

Hollow rods. A special product was developed to work

under rotating loads in PCP and to resist infinite life to fatigue. This results in a "box-box" pipe and a sleeve/pipe nipple connection that allows an external flush joint, i.e. without shoulder in the joint area to minimize turbulence and local loads losses due to flow velocity. A flush connection notably reduces friction between tubing and rod generating savings due to failures decreases as well as reductions in tubing and rod consumption. The Max torque for 48 mm OD Non upset is 1,000 lbxft and 1,500 lbxft for External Upset. (See for details Fig-A9) Control and monitoring.

Variable Frequency Drive (VFD). Every day, the number of VFD are increasing and it has become an important tool for driving the PCP´s, controlling speed, torque and linking down hole sensors information with the drive. This is translated in a better protection of the equipment, bigger run life and production optimization.

Down hole temperature and pressure sensor. Down hole

sensors provide reliable pressure and temperature readings. The sensors are used with controllers and the VFDs to

provide more accurate control on the well based on the changing down hole conditions. In addition, these sensors are used to evaluate reservoir conditions. Until today, only 25 down hole sensor were installed and the first reason for this poor number is the high prices of this products (around 45 % of the total price in a complete equipment for 4,500 ft)

Monitoring- SCADA and data logger. The use of SCADA

systems and/or data logger collectors has been a successes full experience for taking decisions and failure/performance analysis. (See for details Fig-A10)

Failures analysis.

Analyzing information from 800 wells, the range of failure index per year (pulling job/well/year) was 1.0-1.4

This index is bigger than the SRP failure index, and one of the reasons is the PCP´s are used frequently where other ALS couldn’t operate. It’s the case of high flow rate condition (more than 1,000 bpd), more than 90 % of water and sand production.

The most common failures are: - Elastomers fatigue (Histéresys). Common situation at

RPM mayors at 400 RPM, where the right selection of rotor and stator fit is fundamental.

- Premature failure of sucker rods unions for overloading or in the bodies for flexion-torsion combined stresses.

- Tubing and sucker rods friction wear. (See for details Fig-A11)

SPE 108054 5

Others good practices have been implemented for reducing the failure index and improving the systems life:

Test bench in the oilfield: companies as CAPSA, in Diadema oilfield, designed and made a test bench for testing the pumps recovered during pulling operations and the new pumps, too.

Rod string and Tubing wear prevention. The use of tubing

rotator is a new practice, but an interesting trend for improving the life of the systems. ESP (ELECTRIC SUBMERCIBLE PUMPS)

More than 37 % of the total fluid of the basin is produced by ESP with a total of 1,234 pumps running.

The system plays an important role due to the mature state of the basin and the continuous growth of the flow rate and depth of the reservoirs.

The Fig.5 shows a cross-plot depth vs. flow rate with information from 922 active wells.

The total average flow rate is 1,200 bpd and the pump

depth is 6,350 ft. The ESP system covers an application since 3,000 feet

depth to 9,000 ft. The top limit in most of the cases is the temperature and as it begins to increase the flow rate, the horse power transmission is the other limit.

Best Practices and new developments

With the combination of centrifugal pumps, electrical motors, seal chambers, special Makes and separators, surface controls, cables, and new materials technologies, there seems today be something new in the area of ESP’S. Motors. The use of shrouded 375 series motor in 5½” casing is one of the most interesting experience due to the important role of this possibility in multilayer reservoirs opened. (See Operating Electrical Submersible Pumps Below the Perforation).

High temperature motors. As the depth and flow rate increases, the down hole temperature too. The applications of

new insulating materials as PolyEtherEtherKertone (PEEK) are used for increasing the temperature resintence. (500 ºF) Pumps. Radial flow stages and mixed flow stages are used. Been the sand one of the most important problems, abrasion resistant pumps are used frequently.

ARS - (AR Stabilizer), C (Compression) and ARC- (AR

Compression) are used depending of the severity of the sand and well conditions.The severity of sand abrasion depends on a number of factors: Quantity of sand, Acid solubility, Particle size distribution, Quantity of quartz and geometry (angularity)

Seals. Two individual types of seals have been used during the last years: labyrinth and bag chambers.

Multiple arrangement of sealing chambers, labyrinth and bags are used for increasing the life of the motors and system, but new technologies and practices has been applied for increasing the life of the motors, to reduce the number of the protectors and reduce the cost.

Modular Protector. This proven technology of both the labyrinth protector and the positive seal protector are featured in the Modular Protector.

Some submersible applications have required that two or more protectors be bolted in tandem to achieve adequate protection. The Modular Protector could eliminate the cost of tandems by combining multiple protector sections in one unit. Common components are used to assemble multiple labyrinth and/or positive seal sections in a variety of configurations to match individual well conditions or customer requirements. (Fig-A12a)

AR-HT-HL seals. Seal sections can be used in tandem

configurations for increased motor protection. They are available in both bag type and labyrinth-style designs to meet specific applications.

- AR (abrasion-resistant) seals are designed to provide radial stabilization and minimize vibration transmitted to the motor. Up to four chambers in one housing are available.

- HT (high-temperature) seals incorporate specialized elastomers and thrust bearings for increased bottom hole Temperatures.

- HL (high-load) seals employ increased load-carrying capabilities for compression or larger pumps and/or extremely deep applications.

(Fig-A12b) Down hole sensors. A long way for traveling exists in this

area. A few experiences have demonstrated the necessity of improving the technology for increasing the limit of temperature of the sensors, the most common failure in these installations. The technologies exist in the market, but some companies needs to incorporate it in the local area. High-reliability plug-and-play ESP systems with integrated down hole Measurement technology. The system arrive onsite prefilled with oil from a controlled environment, eliminating these difficult tasks at the wellsite. Remaining

Fig.5 – Cross plot pump depth vs flow rate (ESP) from 922 wells

0

2,000

4,000

6,000

8,000

10,000

12,000

0 1,000 2,000 3,000 4,000

flow rate - bpd

pum

p de

pth

- ft

6 SPE 108054

tasks have been simplified. Fewer component connections than previous-generation ESPs and an improved pothead connection result in simpler, shorter installation times and improved quality control of equipment makeup. The technology also has improved capabilities:

- Plug in pothead - Improved heat dissipation and thermocouple to

monitor motor winding temperature in real time operation

- Enhanced materials in bearing on protector head - Higher strength shaft materials on protectors (For graphic details see Fig-A13)

Operating Electrical Submersible Pumps Below the Perforations. The ESP uses the flow of well fluid to cool the motor. This has been traditionally done by landing the ESP above the perforations, or by using a shroud to redirect the fluid around the motor, a typical situation in Golfo San Jorge multilayer reservoirs, where the distance between top and bottom perforation it could be 3,000 ft.

Recirculation electric submersible pump (ESP) systems. As the Fig-A14a shows, the recirculation pump directs fluid though the recirculation tube to the bottom for cooling.

Shrouded ESP. With more than 370 wells installed in the

basin, this practice is one of the main responsible for the increasing flow rate in some oilfields.

Around 99 % of the shrouded ESPs are in 5½” casing with 375 series motor. In spite of this possibility, the shroud often creates some problems, including: misdirected fluid flow witch creates motor heating and excessive heat causes scale buildup between motor and shroud. The Table 3 represents some information about 375 series motor running in Golfo San Jorge.

Min Averag MaxNum of wellsMax HP installed 40 90 130Average intake depth [ft] 4,167 7,300 8,500Flow rate [bpd] 200 533 1,447

more than 370

For graphic details see Fig-A14b

Failures analysis.

Analyzing information from 800 wells, the range of failure index per year (pulling job/well/year) is 0.3 -0.5

Abrasion is a common problem in high flow rate

conditions and high water % in unconsolidated reservoirs or fracturated after compleations. We can mention:

- Excessive radial wear is critical in the top and bottom of the pump due to vibration which can be transferred to the seal or other coupled pumps.

- Excessive Stage down thrust wear which can cut through the impeller shrouds.

- Erosive wear in flow passes which will degrade hydraulic performance.

These problems generally contaminates the seals and a later motors failure appears for lack of insulation.

GAS LIFT When the production flow is of the type multiphase, the

gas lift is one of the most appropriate systems for producing a well, since it simulates a natural flowing. Although the tubing flow or continues gas lift is the most common in the word, exists other techniques as annular gas lift.

Annular Gas Lift. When an important separation exists

between top and bottom perforations, typical configuration in Golfo San Jorge, the use of conventional gas lift (tubing flow) would force to set the packer above the first perforation and the production won't be good.

For this reason the use of Annular Gas Lift (injecting gas through the tubing) is the one of the best alternative and practice in Golfo San Jorge reservoirs. Fig-A15

Although gas lift is one of the most reliable artificial lift systems, the availability of gas compressor plants is a decisive factor for the application of the system.

PLUNGER LIFT This system is used commonly for dewatering gas and

condensed wells that produce below its critical flow. This condition is reached when the speed of the gas in the

tubing is not the sufficiently high thing to drag the liquid particles that consequently finish accumulating in the bottom of the well (load up process).

One of the reasons of the low numbers of wells produced by pluger lift, is others systems as sucker rod pumping with small pumping units are used as dewatering systems for gas wells.

A typical installation consists of a stop and spring set at the bottom of the tubing string and a lubricator and catcher on the surface acting as a shock absorber at the upper end of the plunger's travel. The plunger runs the full length of the tubing between the stop and lubricator. The system is completed with the addition of a controller (time and/or pressure) and motor valve with the ability to open or close the flowline.

Plungers. Depending on the applications, differents plungers are used . Fig-A16

Mini Flex Plunger. It has Eight interlocking stainless steel

pads and a "Flex" design. The surface of the pads is bigger than others plungers and it offers more contact area with the inside part of the tubing string. It`s the most efficient conventional plunger. Used in wells with gas productionless than 5,000 m3/d.

Fiber-Seal Plunger. No moving parts make this an ideal

plunger where sand is present. The efficiency of Fiber-Seal makes its use possible where others will not work. Other application is where tubing restrictions (irregular internal diameter) exist.

Two-piece plunger / plungers with by-pass. The concept of this plunger is to increase the falling speed, and increase the number of cycles.

Table 3. ESP´s with shrouded 375 Series motors

SPE 108054 7

HYDRAULIC JET PUMP Hydraulic Jet pumps have not seen as much use as some

others methods in recent years, but some interesting experiences has been developed recently.

The applications for this method began as a solution for producing wells with high percent of sand where sand control have not been possible to use, and in wells with heavy oil. Another situation is the use in directional wells where others systems have not been possible to use.

Experiences in Diadema Oilfield (CAPSA) and Cañadon Perdido / Restinga Ali oilfields (Repsol-YPF) are the most important in the basin during the last years.

Production of high percentage of sand. To make an

effective sand control in 5½” is very difficult and impossible in most of the cases, when the distance between top and bottom perforation is big. For this reason, to produce the sand could be the only alternative for choosing. The follow example describes the average situation in shallow wells:

Example of Jet Pumps installations Pump /packer depth: 3,000 ft Casing: 5½” Tubing: 2⅞” Power fluid: produced water Power fluid flow rate: 1,100-1,400 bpd Injection pressure: 1,500-2,000 psi Production flow rate: 800-1,200 bpd % of sand: since to 1,000 ppm ( ASTM D-4807) Max. oil viscosity: 28,000 CP@80ºF Where the water supply was a problem, autonomous unit

horizontal PC Pumps were used, allowing the use in remote areas. Fig-A17

Hydraulic jet Pump in a horizontal extended well. The well

is located in Restinga Alí oilfield, operated by Repsol-YPF. The productive reservoirs are located at 1,500 ft (Glauconítico) and a horizontal displacement from the vertical of 3,000 ft. The other particular characteristic is the power fluid is pumped from a vertical well produced by an ESP.

Summary and conclusion

The Table A1 (pag 13) and the figures A18,A19 (pag 12) are presented as a summary.

- Five and half (5 ½") casing provide an important restriction to the technical capacity of the different ALS. It limits the tubing string OD (2⅞"), maximum sucker rod OD (1 ") and the pump diameter (ESP, PCP and SRP). New technologies are developed every day for increasing the flow rate and the hydraulic horsepower transmission, but 7" casing should be evaluated for completing new wells in water flooding projects.

- The distance between top and bottom perforation could be 3,000 ft in deeper wells with more than 20-30 reservoirs opened, presented a big challenger for all ALS for the right production of the reservoirs.

- Sucker Rod Pumping continues being a flexible alternative with a wide operation range. Long stroke pumping units at lower speeds could be an alternative for deep wells or high flow rate conditions. Over size pin sucker and high strength rod are others complementary alternatives for increasing the limit of the system. An important experience exist using pump-off controllers and monitoring, but only 7 % of the wells operated by SRP have this system.

- Progressing Cavity Pumps began as an alternative for low

flow rate, heavy oil and sand production, and is a common alternative to use this system as the last resources for producing problematic wells. For this reason the index failure is bigger compared with others.

PCP is a new system but a competitive alternative for producing high flow rate wells (1,800 bpd @ 3,000 ft) due to the flexibility and smaller initial investment and recent.

Hollow rods have been one of the last innovations in high torque applications, and the first experience in the world was born in Comodoro Rivadavia 8 years ago.

Down hole pressure and temperature sensor are expensive for the most PCPs users, therefore the growth of this important tool will be very slow.

-Electric Submersible motors 375 series operated below

perforations is a success full experience in a basin where the growing flow rate and depth reservoirs in water flooding projects, increase every day.

Down hole sensor is not a common experience and some companies should incorporate proven world wide technology.

High-reliability plug-and-play ESP system is a new but promissory practice.

- Gas Lift system is used in areas where the gas production

is one of the cores of the business and the facilities for compressing gas exist, being this one of the limitations of the growth.

Plunger Lift is used commonly for dewatering gas and condensed wells that produce below its critical flow, and some times the second stage in these wells is to install a sucker rod pump with small pumping unit. In spite of this very interesting experiences have been developed in HGOR oilfields.

- Hydraulic Jet Pump covered a necessity when the

companies needed to produce wells with severity problems with sand production (unconsolidated reservoirs); directional wells and in a horizontal extended well.

Where the water supply was a problem, autonomous unit horizontal PC Pumps were used, allowing the use in remote areas. Other experience is the use of ESP producer well as power unit for producing a horizontal extended well. After 100 years of continuous production, Golfo San Jorge Basin is not only the oldest basin of Argentina, also the first oil producer and with more development during the last years. This has been possible thanks to dedication and professionalism of all people related directly and indirectly with the Industry.

8 SPE 108054

Acknowledgements The authors would like to thank all colleagues of the Golfo

San Jorge Basin for the value of the information and personal experiences.

References

1. Moyano H., Dalle Fiore R., Mazzola R., Ponce C., Ferrigno E: “Application of Intelligent Well Management System to Optimize Field Performance in Golfo San Jorge Basin, Argentina”, paper SPE 95046-MS, presented at 2005 SPE Latin American and Caribbean Petroleum Engineering Conference, 20-23 June, Rio de Janeiro, Brazil

2. Bizzoto P, Dalle Fiore R, De Marzio L, Pan American Energy. Ingeniería de Gas UGGSJ: “Producción simultánea de gas y petróleo en reservorios multicapas del Yacimiento Cerro Dragón” , Tecnoil Magazine. 2006

3. Olmos D. E., Ernst H. A., Villasante J. A., Johnson D. H., Ameglio A. F: “Hollow rods: development of a new technology for PCP”, paper 69558-MS, presented at the 2001 SPE Latin American and Caribbean Petroleum Engineering Conference, 25-28 March, Buenos Aires, Argentina.

4. Dottore.E, De la Vega.N, Bolland "Como mejorar el Desplazamiento Efectivo de las Bombas de Accionamiento Mecánico que trabajan en pozos con Gas libre “ presented at Jornadas de Producción IAPG. Comodoro Rivadavia.2005

5. Figari E., Strelkov E., Laffitte G., Cid de la Paz M., Courtade S., Celaya J., Vottero A., Lafourcade P., Martinez R., y Villar H: “Los sistemas petroleros de la cuenca del Golfo San Jorge. Síntesis estructural, estratigráfica y geoquímica”, IV Congreso de Exploración y Desarrollo de Hidrocarburos, ACTAS I: 197-238. 1999.

6. R.S. Aracena, O.A. Munoz, J.W. KnightBaker Hughes Centrilift: “Experiences with the Recirculation System Electrical Submersible Pump in Argentina ” SPE ATW on ESP and PCP Systems, San Carlos de Bariloche, Argentina. April 17-20, 2005

7. Hirschfeldt M, Segurado J, Pan American Energy; Antoniolli M, Weatherford : “PCPump Automation in Cerro Dragón Area, Golfo San Jorge Basin” presented at SPE ESP and PCP Systems Applied Technology Workshop. Bariloche, Argentina. April 2005

8. Leiguarda D, Palasin M, Pan American Energy; Santos D, ESP Wood Group: “ESP experience in Cerro Dragón Area, Golfo San Jorge Basin” presented at SPE ESP and PCP Systems Applied Technology Workshop. Bariloche, Argentina. April 2005

9. Fernadez Castro H, Nercesian F, Grande R, Pan American Energy; Saiz JJ, Weatherford.: ”Uso de unidades de bombeo de carrera larga” presented at Congreso de Producción IAPG Mendoza 2006

10. García F, Vleugels A, Sanchez J I, Hirschfeldt M, Pan American Energy: “Criterios de selección de bombas mecánicas no convencionales” presented at Congreso de Producción IAPG Mendoza 2006

11. Bertomeu F, Giraldo M, Olivera L, Repsol-YPF; Nvarro F, Schlumberger: “Production optimization through the use of new technologies with electric submersible pumps “ presented at SPE ATW Management of High WOR/High Gross Production Oilfields. November 2006 Comodoro Rivadavia. Patagonia, Argentina.

12. Hirschfeldt M, OilProduction.net “Artificial Lift Experience in Golfo San Jorge Basin” presented at Artificial Lift Conferences IQPC. February 2006. Jakarta, Indonesia.

13. Di Giuseppe, Do Nascimiento, Repsol-YPF “ Experiencia con Jet Pump Hidráulico” presented at Jornadas de SEA. IAPG 2002. Comodoro Rivadavia

14. Gabor Takacs, Ph.D: “Suker rod pumping manual” PennWell Books.

15. Clegg Joe Dunn, Shell Oil Co: “High-Rate Artificial Lift”, paper SPE 17638 PA, presented at the 1988, Journal of Petroleum Technology,

16. Lea James.F., Amoco Production Research; Winkler H.W., Texas Tech U.: “New and Expected Developments in Artificial Lift”, paper SPE 27990, presented at the 1994 University of Tulsa Centennial Petroleum Engineering Symposium, 29-31 August, Tulsa, Oklahoma

17. Lea James F. and Herald W. Winkler: “What's new in artificial lift”, part 1 and 2. World Oil Magazine Vol. 225 No. 4).

18. Brown Kermit E., SPE, U. of Tulsa. “Overview of Artificial Lift Systems”, paper SPE 9979, presented at the 1982, Journal of Petroleum Technology, October.

19. Wilson B.L., Mack John, Foster Danny: “Operating Electrical Submersible Pumps Below the Perforations”, paper SPE 37451-PA, presented at the 1998 Production & Facilities Journal, Vol 13, Number 2, May, pages 141-145.

20. Matthews.C & Skoczylas.P, C-FER: “Surface Drive System Standardization Technologies”. SPE PC Pump ATW Calgary 2003

SPE 108054 9

Fig-A5 – Surface and down hole dynamometric card (left) MII unit, (right) Long stoke unit

APPENDIX

Fig.A1 – Golfo San Jorge Basin Location

Fig-A4 – Long Strok Pumping Units

0

500

1,000

1,500

2,000

2,500

3,000

3,500

Ene

-99

Jul-9

9

Ene

-00

Jul-0

0

Ene

-01

Jul-0

1

Ene

-02

Jul-0

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Ene

-03

Jul-0

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Ene

-04

Jul-0

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Ene

-05

Jul-0

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Ene

-06

Jul-0

6

Tota

l Flu

id -

M b

pd

150

200

250

300

350

400

450

500

Oil

- M b

pd

Fig.A2 – Golfo San Jorge Oil and Total fluid production evolution

OIL

6,000

7,000

8,000

9,000

10,000

11,000

12,000

Ene

-99

Jul-9

9

Ene

-00

Jul-0

0

Ene

-01

Jul-0

1

Ene

-02

Jul-0

2

Ene

-03

Jul-0

3

Ene

-04

Jul-0

4

Ene

-05

Jul-0

5

Ene

-06

Jul-0

6

Num

ber o

f wel

ls

6,000

7,000

8,000

9,000

10,000

11,000

12,000

SRP

PCP

ESP

Fig.A3– Artificial Lift Evolution

WATER

10 SPE 108054

Fig-A6 – Hydraulic Pumping Unit

Fig-A8 – Hydraulic brake

Fig-A9 – Hollow rod

Fig-A10 – Downhole sensor and surface RTU

Fig-A7– Direct Drive Head

Fig-A11 – (a) Histeresys failure process – (b) tubing wear

SPE 108054 11

a b

Fig-A16 – (a) Mini Flex Plunger (b) Fiber-Seal Plunger (c) Two-piece plunger /with by pass

Fig-A17– Jet Pump power unit with horizontal PC Pump

Fig-A12 – Protectors (a) Modular – (b) AR-HT-HL

a b

b

Fig-A14 – (a) recirculationg pump (b) shrourded motor

a

c

Fig-A13 – High-reliability plug-and-play ESP

Fig-A15– Anullar gas lift installation.

12 SPE 108054

Well distribution by flow rate range

0%

10%

20%

30%

40%

50%

60%

70%

80%

0-25

0

250-

500

500-

750

750-

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1000

-125

0

1250

-150

0

1500

-175

0

1750

-200

0

2000

-225

0

2250

-250

0

Range of flow rate - bpd

% o

f the

wel

ls

BME

ESP

PCP

888 wells

6,581 wells

807 wells

Fig-A18– Cross plot flow rate vs. pump depth – 9,760 active wells represented

Fig-A19– Well distribution by flow rate

0

2,000

4,000

6,000

8,000

10,000

12,000

0 500 1,000 1,500 2,000 2,500 3,000 3,500 4,000

flow rate - bpd

pum

p de

pth

- ft

SRP

PCP

ESP

SRP

PCP

ESP

SPE 108054 13

Table-A1– Artificial Lift Summary – SRP, PCP and ESP

Sucker Rod Pumping Progressing Cavity Pumping Electric Submersible Pumping

Number of wells 9,141 1,469 1,234Average Flow rate -

bpd 200 400 1,200

Range of fluid flow rate

72% of wells < 250 bpd 55 % < 250 bpd - 69% < 500 bpd 72 % between 500-1500 bpd

Average Pump Depth - feet 5,384 3,658 6,350

Conventional, Mark II and air balance. Direct and Right angle Drive head

Longe stroke pumping units Electric prime mover

Hydraulic pumping units Hydraulic break for high horse power

Rod pump and tubings pump Tubular and insertable single lobes pumps

Ø since 11/2" to 31/4"

Radial flow stages and mixed flow stages

Seals(protectors) :labyrinth and bag chambers - modular AR/HT/HL

not satisfactory past experiences with 2:3 multilobe pumps (high vibration at rpm >

300

Over size pin: 7/8" SR with 1" pin / 3/4" SR with 7/8" hollow rod 48 mm

Failure Index: Pulling Job / well/ year

0.4 - 0.7 1.0 - 1.4 0.3 - 0.5

Sucker rod breaks (pin )Abrasion and scale

Excessive radial wearExcessive Stage down thrust wear

Erosive wear in flow passes High temperature: poor refrigeration

Data Loggers

Motor temperature

Max torque SR 1" Grade D = 850 lb x ftLong Stroke Pumping Units High flow rate single lobe pumps Pumps Below the Perforations

Hollow rod 48 mm

Failures descrption

Sticking or galling of a metal plunger in the barrel

Sucker rod breaks (pin, coupling and body)

Tubing and sucker rods friction wear.

Elastomers fatigue (Hysteresis)

Control and monitoring

Down hole temperature and pressure sensorSCADA

VFDPump-off controler

375 Series Motors

High Light

Rotor pitch length: 7.8” (200 mm)Flow rate: 490 bpd @ 100 RPMMax lift (100%): 6,500 ft

The temperature limit for NBR elastomer is 195 ºF and 260ºF for HNBR

Power transmition limit: Maximus number of motor S-375 (6)= 128 HP

Casing 51/2" - Tubing 2 7/8"

Pumps / Seals

Sucker Rod

System Limit Maximum SR diameter : 1" / Maximum SPM: 9 and Stroke: 192" in MII units

Grade D and High Strength / use of sinker bars

Mechanical or cup type Hold downs, Ring plunger, Self lubricated plunger, Ring valve, Two Stage Hollow Valve Rod

Pump, Guided valve

Surface Instalations

NBR (acrylonitrile-butadiene rubber) and HNBR (Hydrogenated acrylonitrile

butadiene rubber) elastomers.

ARS - (AR Stabilizer), C (Compression) and ARC- (AR Compression)

Min Averag MaxNum of wellsMax HP installed 40 90 130Average intake depth [ft] 4,167 7,300 8,500Flow rate [bpd] 200 533 1,447

more than 370

Well # 1 Well # 2Setting depth pump - ft 7,850 11,230Pump diameter - in TH-2¼” TH-1 ¾”Pumping UnitSucker rod stringStroke - inSPM 3.9 3.5Fluid Flow rate-bpd 870 125

R-900-360-2891”-7/8"-1 5/8” Grade D

288