Artificial-Lift Systems Overview and Evolution in a Mature Basin: Case Study of Golfo San Jorge Marcelo Hirschfeldt, Paulino Martinez, Fernando Distel

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

This paper was prepared for presentation at the 2007 SPE Latin American and Caribbean Introduction Petroleum Engineering Conference held in Buenos Aires, Argentina, 15–18 April 2007. The East-West trending Golfo San Jorge basin is the oldest 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 and most prolific oil basin of Argentina It covers 28,000 M presented, have not been reviewed by the Society of Petroleum Engineers and are subject to Acre, with 1,127 MMbo (Dec-05) of OOIP and is located in 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 the central Patagonia. (Fig-A1) 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 The first commercial oil discovery took place in 1907 and 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 since then close to 2,900 MMBOE were extracted. Located in 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. the central part of Patagonia Terrane, it is an intracratonic extensional basin. During late Jurassic-early Cretaceous times, Abstract the extension related to the Gondwana break-up generated The Golfo San Jorge basin, located in the central many isolated small half-graben basins, with a NW-SE Patagonia, is the oldest productive basin of Argentina, where structural trend. Later, a new extensional-transtensional stress the first economic discovery took place in 1907, in Comodoro field originated a WNW-ESE trending, and reduced Rivadavia. extensional deformation continued until the Oligocene. With 11,680 active oil wells, is the first oil producer basin The basin is essentially asymmetric; in the eastern section of Argentina producing 258,549 bpd of oil and 2.56 MM bpd the dominant extensional faults are on the northern flank with of water. the southern flanks being a less faulted, flexural type margin. The main characteristics of the basin are: In contrast, the western section is asymmetric but its major - Faults and sand stone lens faults are on the southern flank, being the northern flank a - HWOR flexural margin. The central section of the San Jorge basin is - Increasing fluid flow rate per well dominated by NW and NNW trending extensional faults that - Complex fluids: corrosive, heavy oil, gas, sand and were reactivated by compression in Tertiary times. scale - Multiphase fluids The basin produces 258,549 bpd of oil (44 % of the oil - Multilayer reservoir: from 1.800 to 9000 feet production of Argentina), and 2.56 MM bdp of water (91%) at November 2006. Close to 2.6 MMbpd of water are injected in In this context, the selection, operation and optimization of 2,400 wells in water flooding projects, therefore 41% of the oil the different Artificial Lift Systems (ALS) plays an important is produced from this method. (Fig-A2) role for following the development of the basin. This paper describes the best practices, experiences and Close to 97 % of the wells were completed with 5½” trends, using ALS as Progressing Cavity Pump(PCP), Electric casing, and depending on the companies, new wells are Submersible Pump(ESP) and Sucker Rod Pumping(SRP); and completed with 7” casing. Vertical wells are the most common a basic description about Gas Lift, Plunger Lift and Hydraulic and directional wells are drilled in some projects (water jet Pumping experiences. flooding, parallel to faults) Information as pump depth, flow rates, operational conditions, surface and sub-surface installations description, Artificial Lift System (ALS) in Golfo San Jorge technical limits, failures statistic and new technologies from From the begining of the activity in Golfo San Jorge Basin, more than 9,000 active wells from different oilfields were 100 years ago, several ALS have been used in order to collected and analyzed. produce the oil from each well. As result of this overview, an ALS reference guide was The basin offers different conditions depending the mature completed with parameters and benchmarking indicators; and state of the oilfields: high water percentage, high and low flow some important conclusions appear. rate, free gas and in solution, heay and light oil, flowing wells Complementary information will be presented in the and high GOR reservoirs . Appendix (Fig-A1, A2, Table-A1, etc) 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. Fig.3 – Cross plot pump depth vs flow rate (SRP) from 7,663 wells Distribution and evolution The cross plot (Fig.3) shows a range of depth from 1,000 ft The number of active oil wells is 11,887 with the follow to 10,000 ft for low flow rates. This range of applications falls distribution: as the flow rate requirement increases, representing the mechanical limit of the system (sucker rods and pumping Table 1. Artificial lift distribution units).

System wells % Best Practices and new development. SRP 9,141 76.9 The most important developments and best practices have PCP 1,469 12.4 been applied for increasing the mechanical limit of the system, ESP 1,234 10.4 the cicle of life and to improve the fluid handling, due to the Others 43 0.3 increment of the flow rate and to optimize the production..

Others: Hydraulic Jet pump, Plunger and Gas Lift (nov.06) Pumping units. Common pumping units are: the conventional, Mark II and air balance. Around 45 % of the The Fig.A3 shows the evolution of the most important units are Mark II, being the biggest units 912,000 and artificial lift systems from 1999. 1,280,000 lbxft of torque and only one experience with a MII- 1824-427-216, the biggest pumping units of Argentina. During the last eight years, the number of wells per system it has grown in function of the advance of the technology and Long Stroke Pumping Units. As the depths increase, as of the new requirements of the basin. well as the SPM (stroke per minutes) and stroke length, and PCP is the system that increased the number 237 % from the effective down hole stroke and volumetric efficiency falls. 1999. One of the reasons for this important growth is the new Slower speeds and longer strokes result in more complete development in materials as elastomers, sucker rods, pumps pump fillage and lower dynamic loading. (see the pumping design and surface instalations. And in the other hand, the unit model Fig-A4). This is the main characteristic of this unit. field engineers and companies began to study the system and Dynamometer cards run on these applications are similar to try new challenges. to a theoretically perfect card. An example of a dynamometer The second is the ESP with 224 %, where the growing card is showed in Fig-A5. reservoirs depth and flow rate in water flooding projects forced to the system to reach demanding production forecast The next examples represent two real experiences in Golfo One of the performance indicators we use to measure the San Jorge Basin from seventeen (17) wells runing: failure index of the system is the Pulling Jobs per Well per Year. Table 2. Long stroke pumping units instalations Well # 1 Well # 2 Failure index (FI)=(Pull. Jobs per month /num. of wells) x 12 Setting depth pump - ft 7,850 11,230

Pump diameter - in TH-2¼” TH-1 ¾” Sucker rod pumping (SRP) SRP is the oldest artificial lift in the basin and the most Pumping Unit R-900-360-289 popular with 9,141 units running, In spite of this, the growth Sucker rod string 1”-7/8"-1 5/8” Grade D of the wells from 1999 was 18%, the minimum of the all Stroke - in 288 systems, but this continues being a flexible alternative with a SPM 3.9 3.5 wide operation range. Fluid Flow rate-bpd 870 125 The Fig.3 shows a cross-plot depth vs. flow rate with information from 7,663 active wells. SPE 108054 3

Hydraulic Pumping Units. A few experiences with sealing are with the valve chamber, thus eliminating hydraulic pumping units promise a great development of these irreversible damage to it and the chamber. due to flexibility for managing the speed and stroke length. Fig-A6. Control and monitoring. More than 600 Intelligent Well Controllers (IWC) has been installed in pumping units in Sucker rod string. Grade D ¾”, ⅞” and 1” are the most Cerro Dragón Oilfield (Pan American Energy). These devices common, and some experiences with high strength rods. It´s are connected to RTU that collects and transmit real time usual to use sinker bars for improving the performance of the information as: dynamometric cards, motor, power bands, rod loading. gearbox and production pipe line. The information is recorded and processed for managing the system. Oversize pin sucker rod. This modification was created for increasing the limit of the grade D sucker rod string in Failures analysis. demanding condition of depth and flow rate and reinforcing Analyzing information from 6,000 wells the average FI is the pin of the rod. 0.4 -0.7. Some factors are responsible for the amplitude and The sizes developed are: 3/4 “ SR(sucker rod) with ⅞” pin variability of this index: and ⅞” SR with 1” pin, increasing the capability of the system - The range of depth reservoirs and its characteristics to 15-20% (more flow rate or deepest setting pump). present different fluids and problems(sand, scale, heavy oil, corrosion, temperature) Pumps. Rod pumps from 1½” to 2” in 2⅞” tubing and tubing - Different criteria for inspecting and selecting pumps from 2¼” to 3¼” (in 5½” casing) are used. (See for materials details Fig-A7) - The mature sate of the basin (flow rate, water %) The most common failures are: Hold downs (pumps anchors). Can be mechanical or cup - Sucker rod breaks (pin fatigue is the most common) type. In deep wells bottom and top anchors are used for - Sticking or galling of a metal plunger in the barrel improving the locking. - Tubing wear

Ring plunger. They are intended for use when metal Progressing Cavity Pump (PCP) plungers are unable to produce the well due to sticking or The application of Progressing Cavity Pumps for artificial galling when aggressive sands or large percentages of lifting in Golfo San Jorge Basin is still new compared to other particulates are being pumped. One of the example is the use technologies, but is the second largest systems with 1,469 of fourteen (40) soft rings in shallow wells (less than 3,000 ft), wells and a growth from 436 PCP´s since 1999. high flow rate, high water % and sand. Other practice is the The technology is advancing rapidly and that, combined use the convination between soft and hard rings. with new techniques which are learned empirically, continually expands the range of applications. Self lubricated plunger. This plunger has two seal rings at The smallest investment, compared with other systems, is the extremes of the plunger and it is filled with a silicon fluid one of the reasons of this important growth. between these rings and creating 100% of staunchness Although in their beginnings, the PCP was used to produce between plunger and barrel, ideal for producing fluids with wells with viscous fluids and high contents of solids, the use in sand. high flow rate conditions has been growing every day.

Ring valve or “sand valve” on the valve rod of a rod pump Fig.4 shows a cross-plot depth vs. flow rate with prevent the sand settling between the barrel and the plunger information from 1,175 active wells. during downtime, ensure very efficient pumping operations in gassy wells. 12,000

Two Stage Hollow Valve Rod Pump. It is a rugged pump 10,000 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 t 8,000 A Hollow Valve Rod Pump is its modified upper compression chamber 6,000

Guided valve. Is composes of a hemisphere, penetrated by f - depth pump 4,000 a stem which projects vertically above and below. This B component is called the valve plunger. The stem guide above 2,000 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 0 0 1,000 2,000 3,000 4,000 of violent uncontrolled contact of the ball's multi-surface flow rate - bpd Fig.4 – Cross plot pump depth vs flow rate (PCP) from 1,175 wells 4 SPE 108054

The zone A in the Fig.4 shows a low flow rate area where Suker rods. The standard sucker rods used are 1” and ⅞” the maximum is 300 bpd and a depth range is since 1,800 ft to grade D, and some experiences with high strength rods. 6,000 ft. This area also represents the beginnings of the system in the basin, when the pumps were selected only for low flow Hollow rods. A special product was developed to work rate wells. under rotating loads in PCP and to resist infinite life to fatigue. In the zone B, the depth average is 3,000 ft and a great This results in a "box-box" pipe and a sleeve/pipe nipple flow rate amplitude. This describe the important applications connection that allows an external flush joint, i.e. without of the system in sallow reservoir produced by secondary shoulder in the joint area to minimize turbulence and local recovery (water flooding) where in most of the cases the use loads losses due to flow velocity. A flush connection notably of the same model of pump let to produce from 250 to 1,200 reduces friction between tubing and rod generating savings bpd. due to failures decreases as well as reductions in tubing and rod consumption. The Max torque for 48 mm OD Non upset Best Practices and new developments is 1,000 lbxft and 1,500 lbxft for External Upset. (See for The best practices and technologies have been directed to details Fig-A9) increase the run life and the limit of the system. We can mention some practices: Control and monitoring. - To select the best rotor and stator combination - High flow rate pumps for 5½” casing Variable Frequency Drive (VFD). Every day, the number - Increase the torque limit of the rod string of VFD are increasing and it has become an important tool for - Rod string and Tubing wear prevention driving the PCP´s, controlling speed, torque and linking down - Down hole and surface, control and monitoring. hole sensors information with the drive. This is translated in a better protection of the equipment, bigger run life and Drive heads. Direct and right angle are the two type of production optimization. models used in the basin. (Fig-A7) Electric prime mover is the common installation and IC Down hole temperature and pressure sensor. Down hole motors with right angle drives in remote areas. sensors provide reliable pressure and temperature readings. The sensors are used with controllers and the VFDs to Hydraulic Backspin Control Device. The original drive provide more accurate control on the well based on the heads were designed for small PCP’s in heavy oil service, but changing down hole conditions. In addition, these sensors are as PCP’S increased in capacity, the potentially hazardous used to evaluate reservoir conditions. Until today, only 25 incidents have been increased. Friction Brake with hydraulic down hole sensor were installed and the first reason for this pump is used in drive head where the hydraulic horsepower is poor number is the high prices of this products (around 45 % a critical factor. When the rods backspin, the hydraulic motor of the total price in a complete equipment for 4,500 ft) at the wellhead will force the hydraulic fluid to flow backwards through the system brake and activates the calipers Monitoring- SCADA and data logger. The use of SCADA for griping the disk. (Fig-A8) systems and/or data logger collectors has been a successes full experience for taking decisions and failure/performance Pumps. Tubular single lobe pumps are used made of NBR analysis. (acrylonitrile-butadiene rubber) and HNBR (Hydrogenated (See for details Fig-A10) acrylonitrile butadiene rubber) elastomers. The temperature limit for NBR elastomer is 195 ºF and for HNBR 260 ºF Failures analysis. (information from the manufactures) Analyzing information from 800 wells, the range of failure An small quantity of insert pump for 2 ⅞” tubing are index per year (pulling job/well/year) was 1.0-1.4 running but it´s not a common use. This index is bigger than the SRP failure index, and one of High flow rate pumps for 5½” casing has been the last the reasons is the PCP´s are used frequently where other ALS trends, where the only variable for increasing the volumetric couldn’t operate. It’s the case of high flow rate condition constant of the pump was to increase the rotor pitch length. (more than 1,000 bpd), more than 90 % of water and sand production. Example of high-flow rate single lobe pump The most common failures are: - Elastomers fatigue (Histéresys). Common situation at Rotor pitch length: 7.8” (200 mm) RPM mayors at 400 RPM, where the right selection Flow rate: 490 bpd @ 100 RPM of rotor and stator fit is fundamental. Max lift (100%): 6,500 ft - Premature failure of sucker rods unions for Estimated pump length 45 ft overloading or in the bodies for flexion-torsion combined stresses. Past experiences with 2:3 multilobe pumps were not - Tubing and sucker rods friction wear. satisfactory. Models as 415-4800 (415 bpd@100 RPM- 4,800 (See for details Fig-A11) ft of lift) were operated over 350 RPM and several problems appeared, as hysteresis, high vibrations, tubing and sucker rod failures. SPE 108054 5

Others good practices have been implemented for reducing new insulating materials as PolyEtherEtherKertone (PEEK) the failure index and improving the systems life: are used for increasing the temperature resintence. (500 ºF) Test bench in the oilfield: companies as CAPSA, in Diadema oilfield, designed and made a test bench for testing Pumps. Radial flow stages and mixed flow stages are used. the pumps recovered during pulling operations and the new Been the sand one of the most important problems, abrasion pumps, too. resistant pumps are used frequently.

Rod string and Tubing wear prevention. The use of tubing ARS - (AR Stabilizer), C (Compression) and ARC- (AR rotator is a new practice, but an interesting trend for improving Compression) are used depending of the severity of the sand the life of the systems. 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) ESP (ELECTRIC SUBMERCIBLE PUMPS) More than 37 % of the total fluid of the basin is produced Seals. Two individual types of seals have been used during the by ESP with a total of 1,234 pumps running. last years: labyrinth and bag chambers. The system plays an important role due to the mature state Multiple arrangement of sealing chambers, labyrinth and of the basin and the continuous growth of the flow rate and bags are used for increasing the life of the motors and system, depth of the reservoirs. but new technologies and practices has been applied for The Fig.5 shows a cross-plot depth vs. flow rate with increasing the life of the motors, to reduce the number of the information from 922 active wells. protectors and reduce the cost.

12,000 Modular Protector. This proven technology of both the labyrinth protector and the positive seal protector are featured 10,000 in the Modular Protector. Some submersible applications have required that two or

t 8,000 more protectors be bolted in tandem to achieve adequate protection. The Modular Protector could eliminate the cost of

6,000 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 pump depth - f - depth pump 4,000 match individual well conditions or customer requirements. (Fig-A12a) 2,000 AR-HT-HL seals. Seal sections can be used in tandem 0 configurations for increased motor protection. They are 0 1,000 2,000 3,000 4,000 available in both bag type and labyrinth-style designs to meet flow rate - bpd specific applications. Fig.5 – Cross plot pump depth vs flow rate (ESP) from 922 wells - AR (abrasion-resistant) seals are designed to provide radial stabilization and minimize vibration The total average flow rate is 1,200 bpd and the pump transmitted to the motor. Up to four chambers in one depth is 6,350 ft. housing are available. The ESP system covers an application since 3,000 feet - HT (high-temperature) seals incorporate specialized depth to 9,000 ft. The top limit in most of the cases is the elastomers and thrust bearings for increased bottom temperature and as it begins to increase the flow rate, the horse hole Temperatures. power transmission is the other limit. - HL (high-load) seals employ increased load-carrying capabilities for compression or larger pumps and/or Best Practices and new developments extremely deep applications. With the combination of centrifugal pumps, electrical (Fig-A12b) motors, seal chambers, special Makes and separators, surface controls, cables, and new materials technologies, there seems Down hole sensors. A long way for traveling exists in this today be something new in the area of ESP’S. area. A few experiences have demonstrated the necessity of improving the technology for increasing the limit of Motors. The use of shrouded 375 series motor in 5½” casing temperature of the sensors, the most common failure in these is one of the most interesting experience due to the important installations. The technologies exist in the market, but some role of this possibility in multilayer reservoirs opened. (See companies needs to incorporate it in the local area. Operating Electrical Submersible Pumps Below the Perforation). High-reliability plug-and-play ESP systems with integrated down hole Measurement technology. The system High temperature motors. As the depth and flow rate arrive onsite prefilled with oil from a controlled environment, increases, the down hole temperature too. The applications of eliminating these difficult tasks at the wellsite. Remaining 6 SPE 108054 tasks have been simplified. Fewer component connections These problems generally contaminates the seals and a than previous-generation ESPs and an improved pothead later motors failure appears for lack of insulation. connection result in simpler, shorter installation times and improved quality control of equipment makeup. The GAS LIFT technology also has improved capabilities: When the production flow is of the type multiphase, the - Plug in pothead gas lift is one of the most appropriate systems for producing a - Improved heat dissipation and thermocouple to well, since it simulates a natural flowing. Although the tubing monitor motor winding temperature in real time flow or continues gas lift is the most common in the word, operation exists other techniques as annular gas lift. - Enhanced materials in bearing on protector head - Higher strength shaft materials on protectors Annular Gas Lift. When an important separation exists (For graphic details see Fig-A13) 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 Operating Electrical Submersible Pumps Below the the production won't be good. Perforations. The ESP uses the flow of well fluid to cool the For this reason the use of Annular Gas Lift (injecting gas motor. This has been traditionally done by landing the ESP through the tubing) is the one of the best alternative and above the perforations, or by using a shroud to redirect the practice in Golfo San Jorge reservoirs. Fig-A15 fluid around the motor, a typical situation in Golfo San Jorge Although gas lift is one of the most reliable artificial lift multilayer reservoirs, where the distance between top and systems, the availability of gas compressor plants is a decisive bottom perforation it could be 3,000 ft. factor for the application of the system. Recirculation electric submersible pump (ESP) systems. As the Fig-A14a shows, the recirculation pump directs fluid PLUNGER LIFT though the recirculation tube to the bottom for cooling. This system is used commonly for dewatering gas and condensed wells that produce below its critical flow. Shrouded ESP. With more than 370 wells installed in the This condition is reached when the speed of the gas in the basin, this practice is one of the main responsible for the tubing is not the sufficiently high thing to drag the liquid increasing flow rate in some oilfields. particles that consequently finish accumulating in the bottom Around 99 % of the shrouded ESPs are in 5½” casing with of the well (load up process). 375 series motor. In spite of this possibility, the shroud often One of the reasons of the low numbers of wells produced creates some problems, including: misdirected fluid flow by pluger lift, is others systems as sucker rod pumping with witch creates motor heating and excessive heat causes scale small pumping units are used as dewatering systems for gas buildup between motor and shroud. The Table 3 represents wells. some information about 375 series motor running in Golfo San A typical installation consists of a stop and spring set at the Jorge. bottom of the tubing string and a lubricator and catcher on the

Table 3. ESP´s with shrouded 375 Series motors surface acting as a shock absorber at the upper end of the plunger's travel. The plunger runs the full length of the tubing Min Averag Max between the stop and lubricator. The system is completed with Num of wells more than 370 the addition of a controller (time and/or pressure) and motor Max HP installed 40 90 130 valve with the ability to open or close the flowline. Average intake depth [ft] 4,167 7,300 8,500 Flow rate [bpd] 200 533 1,447 Plungers. Depending on the applications, differents plungers are used . Fig-A16

For graphic details see Fig-A14b Mini Flex Plunger. It has Eight interlocking stainless steel pads and a "Flex" design. The surface of the pads is bigger Failures analysis. than others plungers and it offers more contact area with the Analyzing information from 800 wells, the range of failure inside part of the tubing string. It`s the most efficient index per year (pulling job/well/year) is 0.3 -0.5 conventional plunger. Used in wells with gas productionless than 5,000 m3/d. Abrasion is a common problem in high flow rate conditions and high water % in unconsolidated reservoirs or Fiber-Seal Plunger. No moving parts make this an ideal fracturated after compleations. We can mention: plunger where sand is present. The efficiency of Fiber-Seal - Excessive radial wear is critical in the top and bottom of makes its use possible where others will not work. Other the pump due to vibration which can be transferred to the seal application is where tubing restrictions (irregular internal or other coupled pumps. diameter) exist. - Excessive Stage down thrust wear which can cut through the impeller shrouds. Two-piece plunger / plungers with by-pass. The concept of - Erosive wear in flow passes which will degrade hydraulic this plunger is to increase the falling speed, and increase the performance. number of cycles. SPE 108054 7

HYDRAULIC JET PUMP - Sucker Rod Pumping continues being a flexible Hydraulic Jet pumps have not seen as much use as some alternative with a wide operation range. Long stroke pumping others methods in recent years, but some interesting units at lower speeds could be an alternative for deep wells or experiences has been developed recently. high flow rate conditions. Over size pin sucker and high The applications for this method began as a solution for strength rod are others complementary alternatives for producing wells with high percent of sand where sand control increasing the limit of the system. An important experience have not been possible to use, and in wells with heavy oil. exist using pump-off controllers and monitoring, but only 7 % Another situation is the use in directional wells where others of the wells operated by SRP have this system. systems have not been possible to use. Experiences in Diadema Oilfield (CAPSA) and Cañadon - Progressing Cavity Pumps began as an alternative for low Perdido / Restinga Ali oilfields (Repsol-YPF) are the most flow rate, heavy oil and sand production, and is a common important in the basin during the last years. alternative to use this system as the last resources for producing problematic wells. For this reason the index failure Production of high percentage of sand. To make an is bigger compared with others. effective sand control in 5½” is very difficult and impossible PCP is a new system but a competitive alternative for in most of the cases, when the distance between top and producing high flow rate wells (1,800 bpd @ 3,000 ft) due to bottom perforation is big. For this reason, to produce the sand the flexibility and smaller initial investment and recent. could be the only alternative for choosing. The follow example Hollow rods have been one of the last innovations in high describes the average situation in shallow wells: torque applications, and the first experience in the world was born in Comodoro Rivadavia 8 years ago. Example of Jet Pumps installations Down hole pressure and temperature sensor are expensive for the most PCPs users, therefore the growth of this important Pump /packer depth: 3,000 ft tool will be very slow. Casing: 5½” Tubing: 2⅞” -Electric Submersible motors 375 series operated below Power fluid: produced water perforations is a success full experience in a basin where the Power fluid flow rate: 1,100-1,400 bpd growing flow rate and depth reservoirs in water flooding Injection pressure: 1,500-2,000 psi projects, increase every day. Production flow rate: 800-1,200 bpd Down hole sensor is not a common experience and some % of sand: since to 1,000 ppm ( ASTM D-4807) companies should incorporate proven world wide technology. Max. oil viscosity: 28,000 CP@80ºF High-reliability plug-and-play ESP system is a new but promissory practice. Where the water supply was a problem, autonomous unit horizontal PC Pumps were used, allowing the use in remote - Gas Lift system is used in areas where the gas production areas. Fig-A17 is one of the cores of the business and the facilities for compressing gas exist, being this one of the limitations of the Hydraulic jet Pump in a horizontal extended well. The well growth. is located in Restinga Alí oilfield, operated by Repsol-YPF. Plunger Lift is used commonly for dewatering gas and The productive reservoirs are located at 1,500 ft condensed wells that produce below its critical flow, and some (Glauconítico) and a horizontal displacement from the vertical times the second stage in these wells is to install a sucker rod of 3,000 ft. The other particular characteristic is the power pump with small pumping unit. In spite of this very fluid is pumped from a vertical well produced by an ESP. interesting experiences have been developed in HGOR oilfields. Summary and conclusion The Table A1 (pag 13) and the figures A18,A19 (pag 12) - Hydraulic Jet Pump covered a necessity when the are presented as a summary. companies needed to produce wells with severity problems - Five and half (5 ½") casing provide an important with sand production (unconsolidated reservoirs); directional restriction to the technical capacity of the different ALS. It wells and in a horizontal extended well. limits the tubing string OD (2⅞"), maximum sucker rod OD (1 Where the water supply was a problem, autonomous unit ") and the pump diameter (ESP, PCP and SRP). New horizontal PC Pumps were used, allowing the use in remote technologies are developed every day for increasing the flow areas. Other experience is the use of ESP producer well as rate and the hydraulic horsepower transmission, but 7" casing power unit for producing a horizontal extended well. should be evaluated for completing new wells in water flooding projects. After 100 years of continuous production, Golfo San Jorge Basin is not only the oldest basin of Argentina, also the first - The distance between top and bottom perforation could be oil producer and with more development during the last years. 3,000 ft in deeper wells with more than 20-30 reservoirs This has been possible thanks to dedication and opened, presented a big challenger for all ALS for the right professionalism of all people related directly and indirectly production of the reservoirs. with the Industry.

8 SPE 108054

Acknowledgements 10. García F, Vleugels A, Sanchez J I, Hirschfeldt M, The authors would like to thank all colleagues of the Golfo Pan American Energy: “Criterios de selección de San Jorge Basin for the value of the information and personal bombas mecánicas no convencionales” presented at experiences. Congreso de Producción IAPG Mendoza 2006 11. Bertomeu F, Giraldo M, Olivera L, Repsol-YPF; Nvarro F, Schlumberger: “Production optimization References through the use of new technologies with electric 1. Moyano H., Dalle Fiore R., Mazzola R., Ponce C., submersible pumps “ presented at SPE ATW Ferrigno E: “Application of Intelligent Well Management of High WOR/High Gross Production Management System to Optimize Field Performance Oilfields. November 2006 Comodoro Rivadavia. in Golfo San Jorge Basin, Argentina”, paper SPE Patagonia, Argentina. 95046-MS, presented at 2005 SPE Latin American 12. Hirschfeldt M, OilProduction.net “Artificial Lift and Caribbean Petroleum Engineering Conference, Experience in Golfo San Jorge Basin” presented at 20-23 June, Rio de Janeiro, Brazil Artificial Lift Conferences IQPC. February 2006. 2. Bizzoto P, Dalle Fiore R, De Marzio L, Pan Jakarta, Indonesia. American Energy. Ingeniería de Gas UGGSJ: 13. Di Giuseppe, Do Nascimiento, Repsol-YPF “ “Producción simultánea de gas y petróleo en Experiencia con Jet Pump Hidráulico” presented at reservorios multicapas del Yacimiento Cerro Dragón” Jornadas de SEA. IAPG 2002. Comodoro Rivadavia , Tecnoil Magazine. 2006 14. Gabor Takacs, Ph.D: “Suker rod pumping manual” 3. Olmos D. E., Ernst H. A., Villasante J. A., Johnson PennWell Books. D. H., Ameglio A. F: “Hollow rods: development of 15. Clegg Joe Dunn, Shell Oil Co: “High-Rate Artificial a new technology for PCP”, paper 69558-MS, Lift”, paper SPE 17638 PA, presented at the 1988, presented at the 2001 SPE Latin American and Journal of Petroleum Technology, Caribbean Petroleum Engineering Conference, 25-28 16. Lea James.F., Amoco Production Research; Winkler March, Buenos Aires, Argentina. H.W., Texas Tech U.: “New and Expected 4. Dottore.E, De la Vega.N, Bolland "Como mejorar el Developments in Artificial Lift”, paper SPE 27990, Desplazamiento Efectivo de las Bombas de presented at the 1994 University of Tulsa Centennial Accionamiento Mecánico que trabajan en pozos con Petroleum Engineering Symposium, 29-31 August, Gas libre “ presented at Jornadas de Producción Tulsa, Oklahoma IAPG. Comodoro Rivadavia.2005 17. Lea James F. and Herald W. Winkler: “What's new in 5. Figari E., Strelkov E., Laffitte G., Cid de la Paz M., artificial lift”, part 1 and 2. World Oil Magazine Vol. Courtade S., Celaya J., Vottero A., Lafourcade P., 225 No. 4). Martinez R., y Villar H: “Los sistemas petroleros de 18. Brown Kermit E., SPE, U. of Tulsa. “Overview of la cuenca del Golfo San Jorge. Síntesis estructural, Artificial Lift Systems”, paper SPE 9979, presented estratigráfica y geoquímica”, IV Congreso de at the 1982, Journal of Petroleum Technology, Exploración y Desarrollo de Hidrocarburos, ACTAS October. I: 197-238. 1999. 19. Wilson B.L., Mack John, Foster Danny: “Operating 6. R.S. Aracena, O.A. Munoz, J.W. KnightBaker Electrical Submersible Pumps Below the Hughes Centrilift: “Experiences with the Perforations”, paper SPE 37451-PA, presented at the Recirculation System Electrical Submersible Pump in 1998 Production & Facilities Journal, Vol 13, Argentina ” SPE ATW on ESP and PCP Systems, Number 2, May, pages 141-145. San Carlos de Bariloche, Argentina. April 17-20, 20. Matthews.C & Skoczylas.P, C-FER: “Surface Drive 2005 System Standardization Technologies”. SPE PC 7. Hirschfeldt M, Segurado J, Pan American Energy; Pump ATW Calgary 2003 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

SPE 108054 9

APPENDIX

Fig.A1 – Golfo San Jorge Basin Location

3,500 500

3,000 450

2,500 400 WATER 2,000 350

1,500 300 Oil - M bpd - Oil

Total Fluid M - bpd 1,000 OIL 250 500 200

0 150

Jul-99 Jul-00 Jul-01 Jul-02 Jul-03 Jul-04 Jul-05 Jul-06 Ene-99 Ene-00 Ene-01 Ene-02 Ene-03 Ene-04 Ene-05 Ene-06

Fig.A2 – Golfo San Jorge Oil and Total fluid production evolution Fig-A4 – Long Strok Pumping Units

12,000 12,000

11,000 ESP 11,000

10,000 10,000 PCP 9,000 9,000

ofNumber wells 8,000 SRP 8,000

7,000 7,000

6,000 6,000

Jul-99 Jul-00 Jul-01 Jul-02 Jul-03 Jul-04 Jul-05 Jul-06 Ene-99 Ene-00 Ene-01 Ene-02 Ene-03 Ene-04 Ene-05 Ene-06 Fig-A5 – Surface and down hole dynamometric card (left) MII unit, Fig.A3– Artificial Lift Evolution ( right) Long stoke unit

10 SPE 108054

Fig-A6 – Hydraulic Pumping Unit Fig-A9 – Hollow rod

Fig-A7– Direct Drive Head Fig-A10 – Downhole sensor and surface RTU

Fig-A8 – Hydraulic brake Fig-A11 – (a) Histeresys failure process – (b) tubing wear SPE 108054 11

b a a b

Fig-A12 – Protectors (a) Modular – (b) AR-HT-HL Fig-A13 – High-reliability plug-and-play ESP Fig-A14 – (a) recirculationg pump (b) shrourded motor

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 Fig-A15 – Anullar gas lift installation. Pump 12 SPE 108054

12,000

SRP

PCP 10,000 ESP

8,000

6,000

pump depth ft -

4,000

2,000

0 0 500 1,000 1,500 2,000 2,500 3,000 3,500 4,000 flow rate - bpd

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

Well distribution by flow rate range

80% 6,581 wells SRP BME 70% ESP 807 wells PCP 60% PCP

50% 888 wells ESP

40%

% of the wells 30%

20%

10%

0-250 250-500 500-750 750-1000

1000-1250 1250-1500 1500-1750 1750-2000 2000-2250 2250-2500

Range of flow rate - bpd Fig-A19– Well distribution by flow rate 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 1,234 Average Flow rate - 200 400 1,200 bpd Range of fluid flow 72% of wells < 250 bpd 55 % < 250 bpd - 69% < 500 bpd 72 % between 500-1500 bpd rate Average Pump Depth - feet 5,384 3,658 6,350

Conventional, Mark II and air balance. Direct and Right angle Drive head Surface Instalations 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 ARS - (AR Stabilizer), C (Compression) and ARC- (AR Compression) Ø since 11/2" to 31/4" NBR (acrylonitrile-butadiene rubber) and HNBR (Hydrogenated acrylonitrile Radial flow stages and mixed flow stages Pumps / Seals butadiene rubber) elastomers. Mechanical or cup type Hold downs, Ring Seals(protectors) :labyrinth and bag plunger, Self lubricated plunger, Ring chambers - modular AR/HT/HL valve, Two Stage Hollow Valve Rod Pump, Guided valve not satisfactory past experiences with 2:3 multilobe pumps (high vibration at rpm > 300

Grade D and High Strength / use of sinker bars Sucker Rod Over size pin: 7/8" SR with 1" pin / 3/4" hollow rod 48 mm SR with 7/8"

Failure Index: Pulling Job / well/ 0.4 - 0.7 1.0 - 1.4 0.3 - 0.5 year

Sucker rod breaks (pin ) Sucker rod breaks (pin, coupling and body) Abrasion and scale Excessive radial wear Failures descrption Elastomers fatigue (Hysteresis) Excessive Stage down thrust wear

Sticking or galling of a metal plunger in the Tubing and sucker rods friction wear. Erosive wear in flow passes barrel High temperature: poor refrigeration Down hole temperature and pressure sensor Control and SCADA Pump-off controler monitoring VFD Data Loggers Casing 51/2" - Tubing 2 7/8" The temperature limit for NBR elastomer is Motor temperature System Limit Maximum SR diameter : 1" / Maximum 195 ºF and 260ºF for HNBR SPM: 9 and Stroke: 192" in MII units Power transmition limit: Maximus number Max torque SR 1" Grade D = 850 lb x ft of motor S-375 (6)= 128 HP Long Stroke Pumping Units High flow rate single lobe pumps Pumps Below the Perforations

Well # 1 Well # 2 Rotor pitch length: 7.8” (200 mm) 375 Series Motors Setting depth pump - ft 7,850 11,230 Flow rate: 490 bpd @ 100 RPM Pump diameter - in TH-2¼” TH-1 ¾” Max lift (100%): 6,500 ft Min Averag Max High Light Pumping Unit R-900-360-289 Num of wells more than 370 Sucker rod string 1”-7/8"-1 5/8” Grade D Max HP installed 40 90 130 Stroke - in 288 Average intake depth [ft] 4,167 7,300 8,500 SPM 3.9 3.5 Flow rate [bpd] 200 533 1,447 Fluid Flow rate-bpd 870 125 Hollow rod 48 mm