SPE-SPE-173956-MSNumber-MS

Progressing Cavity Pumps in Horizontal Wells With 2,000,000 Cp Viscosity HydrocarbonsEmmanuel A. Monasterio, Weatherford Internacional de Argentina S. A.Pablo I. Gusberti, YPF

Copyright 2015, Society of Petroleum Engineers

This paper was prepared for presentation at the SPE Artificial Lift Conference - Latin America and Caribbean held in Salvador, Brazil, 27–28 May 2015.

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 been reviewed 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, its officers, or members. Electronic reproduction, distribution, or storage of any part of this paper without the writ -ten 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 SPE copyright.

AbstractThis article describes the techniques and tools for using Progressing Cavity Pump (PCP) that allowed the development of Llancanelo Field, located in southern Mendoza, Argentina, where heavy oil with 12° API is being produced from 13 horizontal wells.

In addition to the heavy oil fluids, several production challenges were overcome to implement the final pumping solution. These challenges are listed below:

• Viscosities up to 2 x 106 Cp at the average surface temperature of 10°C. Pumps were installed at different depths. For example, in the LL-2019 well the PC pump was landed at 3927 m inside a 5½-in. liner, and 90° hole angle well from the vertical reference.

• Flow restrictions caused by sucker rod centralizers.

• Wide operational temperature range, from -15°C in the winter, to 35°C in the summer.

Different strategies have been developed to improve performance on this critical application. Some of these strategies are:

Viscosity and hydrodynamic lubrication wedge/forces reducing the sucker rods and tubing contact, decreasing wear rate and extending the run life before a final failure event.

Ensure to heat surface pipeline and tubing string simultaneously during PCP operation to reduce fluid viscosity and improve the heavy oil flow condition from bottomhole to surface.

Use of Backpressure valves at wellhead to avoid oil leakage on surface during PCP operation and prevent downhole equipment damage caused by overpressure in case of pipeline plugged off due heavy oil viscosity.

Monitoring and automation systems through downhole pressure and temperature gauges.High viscous and heavy oil reservoir development through PCP installation focussed high viscous heavy oil reservoir.

The results of these strategies are explained in detail along this document. Furthermore, an overall balance for the field is presented, based on 7600 m3/y flow rate with 5 wells at the beginning of this project in 2005 and then the flow rate increasing up to 21 727 m3/y with 13 wells in 2013.

In addition, the document shows recommendations and strategies applied on LL-2001 (3621 days) and LL-1003 (4000 days) wells which became in the longest run life for a PCP application registered in Argentina.

Introduction

Llancanelo is a reservoir located in the town of Malargue, in the south of Mendoza state, west of

2 SPE-Number-MS

Argentina, about 1300 m above sea level.

The historical registry of oil explotation in Llancanelo began in 1937, when YPF discovered the reservoir and drilled the well LL-1 with a pay zone at of 76 m. Due to the crude oil physical properties, the lifting cost was too high and further development was halted. Consequently, neither YPF nor any other production company operated in the area until 1965 when YPF returned with additional development efforts. The LL-5 well was drilled and a productive reservoir was discovered, resulting in an additional development of twelve wells over the next 8 years for field characterization and proving of reserves. Proved oil reserves of 4.4 x 106 m3 and probable reserves of 21.5 x 106 m3 were identified as heavy oil, which at that time was unproduceable with existing technology.

Between 1973 and 1981 several attempts were made such as:

Inject hot gas oil with CO2. (1975). Installing a turned off bottom heater

kerosene. (1977). Landing deeper a kind of stove quartz

powered by an electric generator, which was stuck into the inner well walls. (1977).

Injection of various chemicals which attemptsg to reduce viscosity without positive results.

Since 1981 until the end of 1985 a steamflooding project was developed on this area and companies such as Union Oil, Oil Alliance Argentina and Inalruco all of them take over Llancanelo operation.

Union Oil drilled 8 wells identified as LL-1001 to LL-1008 and performed a cyclical steamflooding at 300°C in 6 of this wells. Steamflooding stage used to be for a 1 month. After that, well was shutted down allowing a higher downhole pressure and then well was reactivated, having flow rates between 3 to 9 months. At the beginning wells used to have flow rate was 30 m3/d flow rate by natural flow and after few months was required to install RRL systems, because of due the flow rate decreased up to 3 m3/d.

Although steamflooding project was capable to achieve an oil flow rate closed to 19 000 m3, this crude oil was not accepted for processing at refinery and therefore project was cancelled.

On 18 May 1996 the first PCP model 24-2000 (24 m3/d/100rpm pump displacement and 2000 m nominal lift) was installed as field trial in LL-1003 well. Registered a stable flow rate was 20 m3/d.

In 1999 a new project began, this time focused on heavy oil cold production in horizontal wells. Field activity came back under YPF’s responsibility and

LL-2001(h) well was drilled, becoming in the first horizontal well with PCP system installed on this area. Based on the success achieved after PCP installation, other additional 40 wells were proposed to drill. However, this project was on hold due envorinmental protection to nature reserve in this area.

Between 2000 and 2010 the nature reserve’s area was expanded to 87 x 107 m2 and hydrocarbons activities were approved following high environmental and safety standards.(D’amico 2011)¹.

Produced Fluid Description:

Fig.1 shows viscosity data measured at surface conditions from some representative wells of the reservoir and Table 1 shows useful parameters measured to provide a better fluid characterization. In general, this high viscosity implies a concern in terms of transportation and lift, for every single artificial lift system to be installed.

0 10 20 30 40 50 60 70 80 90 1000

500000

1000000

1500000

2000000

2500000

Viscosity profile in PCP wells at Llancanelo field

Ll-1003 Ll-2001 Ll-2012 (10/2011)Ll-2010(10/2011)

Temperature (°C)

Visc

osity

(Cp)

Fig. 1—Viscosity profile in PCP wells at Llancanelo field.

Ll-2012 Ll-2010 Ll-2013Density g/cm3 @15° 0.9842 0.9879 0.9854

°API 12.20 11.80 12.1

Point of runoff, °C 27 24 12

Paraffin waxes, % < 5% < 5% < 5%

Table 1 — Llancanelo produced fluid characterization.

Strategies developed

Hydrodynamic lubrication

Because of the horizontal well geometry rod centralizer were expected to be required in this project. The PCP simulation showed a high contact load value between available tubing string and sucker rod string. Under these conditions, the proposed design was not feasible. However, once

SPE-Number-MS 3

centralizers were removed from rod string, the results improved significantly in terms of contact load and PCP design was a suitable one to install.

A concrete example of this was the LL-2001 well which bottomhole assembly considered included a model 16-3000 PC pump landed at 900 m with 47° hole angle well; 1-in. D Grade sucker rods; tubing 3½-in. The average operational speed was 150 rpm, 27% water cut and 21 m3/d average flow rate.

Higher contact load of 2691 N (605 lbf) registered at 817 m. The expected tubing string run life for this application was 59 days, which means that wear rate was 630%/year.

Fig. 2 shows one well representation of the vertical section and PC pump landing depth.

Fig. 2—LL-2001 well vertical section.

Fig. 3 exhibits LL-2001 well tubing wear profile in terms of tubing wear rate along the well.

Fig. 3—Tubing Wear Profile.

Even with this prediction, on 16 May 2003 the second PCP sytem installation was performed as a test pilot and with outstanding results considering well has been continuously operating over 3621 days (9 years 11 months).

The PC pump was removed from the well on 14 April 2013, because of a rod string broken. During

intervention, rotor was inspected and found in good condition, with relatively slight signs of wear and tear. Stator had signs of wear due hole angle well at landing depth. This pump had a good performance until the rod string failure.

According to Argentinian Energy Department statistics², well flow rate from January 2006 to April 2014 was 30 114.73 m3. Extrapolating to installation date, throughout its run life, the PCP system was capable to achieve a cumulative flow rate of 40 994.52 m3.

24/03/201316/12/200911/10/200803/10/200613/02/20040

40

80

120

160

200

LL-2001 well performance history[m3/d] RPM volumetric efficiency

Date (day/month/year)

Flow

Rat

e (m

³/d),

Pum

p Sp

eed

(rpm

), Pu

mp

volu

met

ric

effic

ienc

y (%

)

Fig. 4̶—LL-2001 well performance history.

Fig. 4 shows well flow rate history and PC pump volumetric efficiency change over the years. Fig. 5 shows the top and bottom elastomer thickness condition after pulled out the stator, it’s noted a higher wear of elastomer at stator bottom section as a result of rotor weight effect operating over 9 years and influenced by pump inclination at landing depth. Minimum elastomer wear is exhibited on estator top section.

Fig. 5—Stator Ll-2012, top and bottom elastomer thickness condition.

The unexpected tubing string run life may be justified once the relative sucker rod string relative rotation through tubing string is defined as a sliding bearing. This type of bearing would be classified as a completed hydrodynamic lubricant thickness, since the load bearing surfaces (the sucker rod coupling surface and the inner tubing wall for this specific

Stator Top Section

Stator Bottom Section

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case) are completely separated by a lubrication substance (viscous oil). This lubricant is adhered to the surfaces and then is driven by the moving surface toward the wedge-shaped space with progressive narrows resulting in an increase of pressure in the fluid film which gives support to the moving part.

The conditions to generate the hydrodynamic layer were:

1. The clearance between the surfaces is greater than the roughness.

2. Surfaces have relative motion.3. Non parallel surfaces.4. Viscous and oily fluid.

These conditions are fulfilled in our applications could therefore calculate the "index bearing", "bearing characteristic number" or "Number of Sommerfeld".

S=( rc )

2

µ NP

…………………………………………(1)

Where:S = bearing index.r = radius of the stump.c = radial clearance.μ = absolute viscosity.N = relative speed of rotation.P = load per unit area.

Raimonde and Jhon Boyld³ developed charts experimentally and computer iteration allowing us following the number of Sommerfeld determine, among other parameters, the lubrication thickness.

Considering:

P=WLD

..................................................................(2)

Where:W = Load per unit area.L = rotational bearing length.D = rotational bearing diameter.

And simulating the sucker rod string operation in PCP application similar to a bearing system; therefore is possible to correlate well operational data to calculate Sommerfeld number.

Well operational data:

Total diameter of the bearing = 2.992-in. (ID 3½-in. tubing).L = 1-in. coupling length = 4-in.

D = 1-in. coupling diameter = 2,187-in.L/D = coupling length/coupling diameter ratio = 1.83. W = Load per unit area = 605 lbf.cd = Radial clearance = 0.3565.N = 2.5 rps.μ = 61000cp (approximately 28°C) → Ne = 0.009 reyn.

Solution:

P= WLD

= 6054∗2.187

=69.22 psi=477.3 kPa

By replacing corresponding available values to Eq. 1, the Sommerfeld number is calculated as follow:

S=( rc )

2

µ NP

=(1.09350.3565 )

2

∗0.009∗2.5∞

69.22=0.003

Then, with S = 0.003 and L/D = 1.83 is possible to use Fig. 6 to determine the lubrication thickness as follow: h0/C = 0.015.

Fig. 6—Lubrication thickness calculation in terms of Sommerfeld number³.

Calculating the lubrication thickness for the PCP Llancanelo application,

h0

c=0.015 → h0=0.015∗c=0.015∗0.3565=0.0055∈.

Based on operational conditions, there is a 0.005-in. lubrication thickness between the sucker rod and tubing joints that decreases considerably the tubing/sucker rod wear rate while PCP system rotation.

It is noteworthy that the lubrication theory is mathematically very complex. Simplifying

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assumptions must be considered in order to obtain approximate results.

Ensure to heat surface pipeline

Considering oil produced had a high viscosity and even with the the shorter distance implemented to the storage tank, the flow loses in surface pipeline still have a prominent values.

Low temperature caused flow restriction because of high viscosity oil. Then, was required to find a suitable way to decrease oil viscosity.

All efforts were focused on maintaining oil high temperature from the bottom hole to the storage tank.Therefore, an electric heating system was installed which includes heat resistance device installed up to 500 m depth jointed to the outter tubing wall. Also, surface pipeline is convered with isolation heat tape from well head to storage tank and one power heating resistance in located inside the storage tank to keep fluid viscosity as lower as possible.

At bottom hole, the average oil temperature is 56°C and once produced fluid gets to the surface, its temperature could change up to 25°C.

In some of these wells, as seen in Table 1, the oil has 27°C as a point of runoff. Therefore, is required to keep wells over these temperature threshold values.

Around 45°C has been achieved using the heat resistance device. As a result of the botomhole tubing string isolation and the second stage of heating the surface pipeline, the different wells connected to the same tank achieved temperature around 56°C.

Considering these temperatures, both real and simulated parameters were improved.

Main parameters comparison before heat resistance device installation on downhole tubing string: As an example the data obtained specifically in the LL-2012 well, shows the total flow losses were reduced by 52%, the maximum rod torque decreased by 28% and pump discharge pressure also decreased by 40%. These values are approximate.

Table 2 shows the results simulated for the two conditions, bottomhole tubing string, and surface pipeline before and after install heat resistance device and isolation heat tape.

Basic ParametersWellhead Temperature25° C 44° C

Flow Losses [kPa] 12 749.5 6185

Pump Discharge Pressure [kPa] 20 836 14 229.8

Pump Pressure Loading 131.06 % rated 87.53 % rated

Maximum Rod Torque 604.76 ft·lbs 435.03 ft·lbsTable 2 — LL-2012 PC pump simulation before and after increase bottomhole temperature.

Use of Backpressure valves at wellhead

In the possible scenario of any failure in power supply or the heating system is turned off for some reason it was necessary to have at least one mechanical tool designed to operate as a safety barrier and would allow to protect surface pipelines and downhole equipment from a pressure buildup condition.

This mechanical tool is a ball and seat valve normally closed, forced by a spring acting in the opposite direction from surface pipeline pressure (See Fig. 7 and Table 3). When pressure in the pipeline takes higher than pressure on the spring, the valve opens and passes up the fluids flow.

Fig. 7—Backpressure valve diagram⁴.

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Position DescriptionA Lower Conector.

B Tee coupling body.

C Upprhead.

D Regulator Screw.

E Spring Support.

F Spring.

G Nut Lock.

H Conic Plug.

I Parker 2-213 O´Ring.

J Ball.

K Seat.

Table 3 — Backpressure valve components⁴.

These valves are normally used in RRL systems. For PCP applications, the valve must be installed on a bypass connection assembled above the production Tee, allowing the valve to pump all fluids coming from botomhole in backflow direction through casing section.

Safety pressure in valve can be set through turning itsscrew. The selected safety pressure will depend on several parameters such as the PCP lift capacity, operational pressure on wellhead, flow rate and surface flow losses.

Fig. 8 shows an installation scheme of a PCP wellhead, backpressure valve is distinguished in red, installed as part of the bypass pipeline section and connecting production line with casing section line.

Fig. 8—Backpressure valve installation scheme on surface wellhead.

This device never had a problem in regards spills or breakages, in all wells where this tool has been installed at this nature reserve.

Furthermore, the tool allows protecting PC pump from backpressure conditions that eventually could compromise elastomer integrity. This ultimately release on extends equipment run life.

Pumps Geomety selection.

Another technical consideration for this project was the PCP geometry selection because of the heavy oil and high viscosity application. Then, rotor swept angle selected was a shorter one in order to get a larger cross-sectional area which is the most suitable condition to overcome this kind of application. Moreover, PCP designs an ideal condition for this kind of application. Designs were focused on ensure a lower operational speed to improve PC pump performance in terms of cross-sectional area filling and therefore improve overall system efficiency for this application.

Table 4 shows models available in Argentina region during development stage of Llancanelo field. In general, these PC pump models have a small rotor swept angle and high cross-sectional area to improve PCP performance in high sand cut and/or high viscosity fluid applications. Moreover, Table 4 PC pumps listed in green were installed in Llancanelo area, considering they have the lower values in terms of rotor swept angle.

Model [m3/d/100RPM]

Nominal Pump Displacement [m3/d/RPM]

Swept Rotor Angle

[°]

Pump Outside Diameter

[mm]4 0.041 30.08 737 0.068 44.8 73

10 0.102 32.2 9514 0.136 40.1 8916 0.166 30.8 10617 0.169 46.4 8922 0.221 38.5 10624 0.245 31.8 114

Table 1 — PC pump models available and used for Llancanelo project.

PC pumps for this application used to be landed in average at 900 m, which is equivalent to 15 000 kPa diferential pressure. Although, the PC pumps installed rated pressure are between 19305 kPa, and 28958 kPa. Therefore, the PC pumps installed for Llancanelo application are operating with an important safety margin around 48% rated pressure.

Pumps selected with these low rotor swept angle and higher lift values, showed outstanding results in Llancanelo field application. As a reference, LL-1003 well was installed in 2001 and has been constinously operating for over 4760 days, becoming in the PCP application with the longest run life registered in Argentina.

LL-1003 well is vertical, with a PC pump model 24-2400 NBRA installed, landed at 930 m and 74.2%

SPE-Number-MS 7

pump volumetric efficiency. Current operational speed is 80 rpm, with 15 m³/d flow rate. These PCP conditions are outstanding considering system has been operating continuously over 13 years.

According to Argentinian Energy Department statistics⁵, well flow rate from January 2006 to January 2016 was 9925 m3 oil and 37 956 m³ water

Extrapolating to installation date, throughout its run life, the PCP system was capable to achieve a cumulative flow rate of 14 337 m3. (See data in Fig. 9)

12/03/201425/11/200905/06/200805/09/200426/10/2001020406080100120140160180

LL-1003 well performance history

[m3/d] RPM volumetric efficiency

Date (day/month/year)

Flow

Rat

e (m

³/d)

, Pum

p Sp

eed

(rpm

), Pu

mp

volu

met

ric

efficie

ncy (

%)

Fig. 9—LL-1003 well performance history.

PCP pump landed at high hole angle well.

Another outstanding application is the LL-2019 well. In this case, PCP was landed at 1200 m within a 5½-in. liner from 839 m to 1916 m. PC pump was seated in the horizontal section of well geometry, wherein angle hole well was 92.78º.

In Fig. 10, well vertical section is shown including pump landing depth. Fig. 11 shows the tubing wear simulation done for LL-2019 well, taking into account the rod and tubing contact load along the well. According to simulation, the highest tubing wear value is 275%/year at 447 m, therefore maximum run life in this well before failure would be 127 days.

Even with this critical tubing wear simulation results, it was taken into account the previous experience adcquire on LL-2001 well and the hydrodynamic lubrication effect to proceed with the PCP system installation.

Fig. 10—LL-2019 well vertical section view.

Fig. 11—LL-2019 well tubing wear profile.

The PC pump at LL-2019 well was installed on March 2014, with 8 m3/d flow rate registered. This PCP system has been operating continuously by 335 days with no interventions required

Stuffing Box replacement

The oil leakage because of failures on stuffing box rope packings at wellhead were pretty common and demanded a lot of work for preventive and corrective maintenance routine. This was one of the main troubles to control particularly in Llancanelo field as a nature reserve.

The equipments installed until 2010 had conventional stuffing box, with a rope packing configuration as shown below, on Fig. 12 is shown a conventional stuffing box profile:

Fig. 12—Conventional stuffing box configuration.

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While the performance of conventional stuffing box have been enough in the majority of applications, For Llancanelo field operational conditions was required to apply a new technology to ensure zero leakage on PCP systems installed.

Conventional stuffing boxes were gradually replaced with injectable packing basically composed of grafite raw material in a lubricant oil base, which ensures a longer run life because of the lubrication. (See Fig. 13).

This special grease is injected with a manual pump through a high pressure valve.

Fig. 13—Injectable packing stuffing box configuration.

Also, stuffing box has two pairs of seals with metal body and vulcanized elastomer that seals inconjunction with the polished rod.

The seals effect is uniform and constant.

The combined effect of these two components, the teflon fiber/raw material and the seals, offer extended run life in operation with zero leakage events.

Some advantages of this stuffing box model are the reliability and easy operation for Llancanelo field application. Conditions such as extended run life in rope packing and no short time leakage events registered, places this technology as a proper one to be installed in critical areas like nature reserves.

While one conventional stuffing box requires an average a rope packing repair routine every six months, and during that time several cleaning and connection adjustments assistance, this stuffing box model has shown low maintenance requirements, because it needs to be tighten once a month as a preventinve activity, which realeases in zero leakage events. Based on data from all reservoir located at central Argentina area, was established the minimum time for stuffing box replacement from 3 to 4 years.

Before to start with rope packing stuffing box maintenance is required to shutdown the PCP system and to liberate the stored energy as

backspin. Once the well has stopped, is allowed to replace the rope packing kit.

Results

Since 1996, during 18 years of PCP experience in Llancanelo field, only 8 interventions have been registered with pulling equipment because of any system failure.

In the last seven years is only one intervention has been recorded because of pump failure that was a supplied by another vendor, at Ll-2013 well.

Some interventions have been taken place to install new PCP driveheads as a preventive action. However, by the time of this replacement the equipments were operating in standard conditions. Other interventions were caused by sucker rod failure, such as LL-2060 and LL-2035 where the broken rods were replaced and the well continued operating with the same PC pump installed.

These results represent substantial savings on intervention costs and lower failure intervention index, as well.

Analyzing the last three years it can be shown that expenses in regards PCP well interventions at Llancanelo field are lower in comparison with PCP intervention expenses in others fields from Malargue area.

Fig. 14 summarizes annual PCP intervention expenses for Llancanelo field and others fields from Malargue area.

2012 2013 2014USD 0.00

USD 5,000.00USD 10,000.00USD 15,000.00USD 20,000.00USD 25,000.00USD 30,000.00USD 35,000.00

Spending on interventions PCP/ n° wells PCP

Llancanelo Loma Alta Sur Cerro fortunoso

Fig. 14—Total PCP intervention expenses per year.

Three indicators were analyzed to compare the field performance at Malargue area under the same

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criteria. These indicators are listed below:

Mean Time Between Failures, MTBF=

∑i

1

ti

kf

Run Life, RL=

∑i

1

¿

ko

Mean Time Before Failure, MTTF=∑ ¿+ti

kf

Where:

Ti = Accumulated operating time of failed equipment.Kf = number of failed equipment.To = Cumulative operation time of operating equipment.Ko = Number of operating equipment.

Applying these formulas to oilfiled historical records⁶, it is possible to obtaing the following values:

IndicatorMax.

Llancanelo [days]

Max. Loma Alta Sur [days]

Max. Cerro Fortunoso

[days]MTBF 1687.6 538.18 353

Run Life 2678.5 950 439.81MTTF 4410 612.16 418.14

Table 5 — Performance indicators for fields at Malargue area.

Also, is important to analyze how many wells have been operating; this information is shown in Fig. 15:

Fig. 15—Llancanelo field run life performance indicator.

Another way to quantify the results obtained with the use of progressive cavity pumps at Llancanelo area is to compare the flow rate statistics in the past with current data.

In 2005 there was only 4 producing wells, with PCP system installed and 7 600 m3/d flow rate. Currently there are 15 producing wells with 29 115 m3/d flow rate at 2014.

Fig. 16 shows the monthly flow rate report from 2006 to 2014. The decrease in production in April of 2014 was caused by unexpected closed of oil treatment facilities.

Fig. 16— Llancanelo field historical fluid rate report.

Besides technical results related to flow rate and well performance, in over than 18 years operating this field, there has no been any environmental and safety incidents.

Based on these results, the original project has been extended for 25 new wells using the same technology, including monitoring and optimization systems, with downhole temperature/pressure gages.

Conclusions:

For over 50 years, profitable extraction and exploitation of the area were delayed due to various technical and environmental causes. The progressing cavity pump artificial lift system supplied a solution to the technical troubles with outstanding operational and environmental performance.

The lubricating thickness through sucker rod string and tubing string caused by fuluid viscosity has avoided wear effect on PCP downhole equipment installed at Llancanelo field.

Some good practices such as heat resistance installation, use of backpressure valves as well as PC pump aggressive geometry were crucial

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to achieve the described results ar Llancanelo field.

References

1. DAmico, P. 2001. Conflictos por Explotación Petrolera: Aproximación a su Estudio en la Laguna Llancanelo, Mendoza”. In II congreso Lationamericano de Histroia Economica y XXIII Jornadas de Historia Economica. Simposio 9: Politicas Petroleras en America. 14.Argentina (May 2011).http://www.aahe.fahce.unlp.edu.ar/jornadas-de-historia-economica/iii-cladhe-xxiii-jhe/ponencias/DAmico.pdf 

2. Argentinian Energy Departmenthttps://wvw.se.gob.ar/datosupstream/consulta_avanzada/reporte.sql.php?idempresa=YPF&idmes_d=1&idanio_d=2006&idmes_h=1&idanio_h=2016&idcuenca=NEU&idprovincia=M&idarea=LLA&idyacimiento=LLA&idpozo=114062

3. Shigley, J.E and Mischke, C.R. 2008. Cojinetes de contacto deslizantes y lubricacion. In Diseño En Ingeniería Mecánica, sixth edition., Chapter#12, 753-773. Mexico City, Mexico: Mc Graw Hill.

4. Backpressure valve TSS. Weatherford de Argentina. April. 2010.

5. Argentinian Energy Departmenthttps://wvw.se.gob.ar/datosupstream/consulta_avanzada/reporte.sql.php?idempresa=YPF&idmes_d=1&idanio_d=2006&idmes_h=1&idanio_h=2016&idcuenca=NEU&idprovincia=M&idarea=LLA&idyacimiento=LLA&idpozo=114018

6. SET” Performance System. Operations Module. Weatherford Internacional de Argentina S.A.

7. Software “PC-PUMP” versión v3.3.6.15528

Acknowledgements

Diego Lodos, Area Manager, YPF S.A. – Malargüe Norte, Mendoza.

Ing. Claudio R. Alonzo, Production Superintendent, YPF S.A. – Malargüe Norte, Mendoza.

Walter Antonio Barraza Paz, Well Service, YPF S.A. – Malargüe, Mendoza.

Ing. Pablo Gusberti, Production Engineer, YPF S.A. – Malargüe Norte, Mendoza.

Ing. Laura Sirvent, Production Engineer, YPF S.A. – Malargüe Norte, Mendoza.

Miguel Angel Serrano, PCP Supervisor, Malargüe, Weatherford Internacional de Argentina S.A.

Miguel Angel Maestre, Base Manager, Malargüe, Weatherford Internacional de Argentina S.A

SI Metric Conversion Factors

m³ x 0.1589873 bbl m x 0.3048 ftkPa x 6.89476 psi

Nomenclature

r = radius of the stump.c = radial clearance.µ = viscosity, m/Lt, cP.L = length, L, in.r = radius, L, in.Ne = Reynolds Number.