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PCP Sand Handling TechnologiesMariano Montiveros, Pluspetrol S.A; Lucas Echavarria, Pluspetrol S.A.; María Briozzo, Weatherford

Copyright 2013, Society of Petroleum Engineers

This paper was prepared for presentation at the SPE Progressing Cavity Pumps Conference held in Calgary, Alberta, Canada, 26–27 August 2013.

This paper was selected for presentation by an SPE program committee following review of information contained in an abstract submitted by the author(s). Contents of the paper have not beenreviewed by the Society of Petroleum Engineers and are subject to correction by the author(s). The material does not necessarily reflect any position of the Society of Petroleum Engineers, itsofficers, or members. Electronic reproduction, distribution, or storage of any part of this paper without the written consent of the Society of Petroleum Engineers is prohibited. Permission toreproduce in print is restricted to an abstract of not more than 300 words; illustrations may not be copied. The abstract must contain conspicuous acknowledgment of SPE copyright.

 Abstract

Experience tells us that progressing cavity pumping is the logic choice for producing heavy sandy fluids. Nevertheless, underthese conditions PCPs suffer from blocked suction, sanded pump and low runlife. In order to overcome these issues two

technologies were tested simultaneously: charge pumps and medium nitrile elastomer.

The fields involved in this study are El Corcobo Norte, Cerro Huanul Sur, El Renegado, Jagüel Casa de Piedra and PuestoPinto which produce from the Centenario Formation and are located in the Neuquen Basin. These are non-consolidated

sandstone formations with an oil gravity of 18 °API that are produced following CHOPS philosophy (Cold Heavy Oil

Production with Sand), where sand production is deliberately maintained through time.

In 2010 the first charge pump PCP was installed, followed by six more wells in the course of two years. This system proved

to be an alternative for high sand cut wells (4-5% continuous and up to 25% slugs) and also reduced by half flush-byinterventions due to sanded pump.

Also in 2010 started the trials with a softer elastomer (medium nitrile).The sanded pump failure rate was lowered (comparing

 pumps with the same volumetric capacity and in the same well), reducing downtime and hence increasing production. These

 pumps also showed higher operating efficiency and longer run life than high nitrile pumps.

These results encouraged us to integrate both technologies, resulting in the installation of charge pump PCPs with mediumnitrile elastomer during the last quarter of 2012. In 2013 we will field test pumps with enhanced geometry. This is all part of

a combined effort for finding reliable and cost effective solutions for challenging applications.

Introduction 

The Corcobo Norte field and its neighbours, Jagüel Casa de Piedra, Cerro Huanul Sur, Puesto Pinto, El Renegado andGobernador Ayala Este belong to CNQ-7/A, CNQ-7 and Gobernador Ayala III areas, which are located north to the Río

Colorado, in the argenitinian provinces of Mendoza and La Pampa (Cevallos et al. 2011).

In 2004 Petro Andina Resources Ltd. began operation in these areas, acquiring 50% of the exploratory blocks in the northeast

margin of the Neuquen Basin. Two societary groups were formed, one with Repsol-YPF in the CNQ-7/A area and anotherwith Repsol-YPF and Petrobras in the CNQ-7 area. In 2007 another society was formed with Enarsa and Raiser to operate

Gobernador Ayala III. In 2009 Petro Andina Resources Ltd. sold its assets to Pluspetrol S.A., the current operator.

Exploration of these areas started in 1964, being Jagüel Casa de Piedra (JCP) x-3, drilled in 1984 by YPF, the first well toshow presence of heavy underpressurized oils in sand producing unconsolidated reservoirs. This region lack exploratory

interest, due to its poor production and its small scale, defined by three advance wells (JCP.a-4 and a-5 nonproductive and a-

6 which produced both oil and water).

Based in the findings of JCP.x-3 Petro Andina Resources Ltd. initiated in 2004 an intense exploration campaign, that took

advantage of the objectives’ shallow depth. This was the first profitable exploration campaign. Stratigraphic traps with over550 million BO OOIS (original oil in situ) were found during this period.

The main reservoirs in this area are non consolidated sands from Centenario Formation, with over 60% of the reserves in the

Lower Member while the rest are in the Upper Member. The best reservoirs from both the Lower and Upper Member are

coastal plateu fluvial channel deposits, with an average reservoir depth of 600m (1970ft). The average porosity is 30% whilethe permeability ranges from 0.5 to 4 Darcy, being the average 1 Darcy. The average height is 8m (26 ft) but intervals as high

as 18m (59ft) have also been found. Most of the oil has an API gravity of 18° and 160-270 cP in situ viscosity, though extra

heavy oils have also been found.

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From the beginning the strategy used was created upon the study of the exploration and development of similar heavy oil

Canadian fields. It was also decided to try every technology that proved successful in other fields in a time frame of three

years.Two technics were tested simultaneously: cold heavy oil production with sand (CHOPS) and pressure control with water

injection. Other techonologies such as continuum vapor injection, cyclic vapor injection and horizontal drilling were tested in

 parallel but discarded due to its poor results for the field devolpment phase.

As of October 2012 the total net production of these areas was 4527 m3/d (28365 BOPD) with 470 active producing wells.

Water injection reached 18600 m3/d (116541 BFPD) with 269 injection wells. Additionaly, there are eight gas producingwells that supply energy to the whole area.

As mentioned earlier, these fields are located north to the Rio Colorado in the provinces of Mendoza and La Pampa. Fig. 1.a and 1.b ilustrate this:

Figure 1.a Figure 1.b

 Field Development

As the field was developed new border zones were perforated and two meters height intervals were found. These newintervals are heterogenous and even less consolidated than those from the central zones. Wells with larger useful intervalswere also found, but they required more perforations (Montiveros et al. 2012).

From early on there was a high premature vulcanization failure rate. This failure is associated with dynamic pressure, which

in these wells is kept at its minimum, almost at perforations level, due to their low productivity. This is aggravated by high

viscosity, low water cut and stable emulsions; resulting in uncomplete cavity fillage and lack of lubrication. Since theelastomer has poor heat transfer properties, the lack of lubrication causes a temperature increase that in time burns the

elastomer.

The proposed design for ensuring fluid flow to the pump suction was installing the pump below the perforations. Thisapproach was abandoned since the torque anchor usually got stuck due to solids settling. Installing the pump above the

 perforations and tubings below the anchor is not convenient for these applications because the suction flow area is less than

when using a slotted nipple.

As the field production evolved, the pump failure mode changed from 100% vulcantization to loss of efficiency. Operating

speed was increased to compensate low efficiency, but at a higher risk of tubing and rod failure. The next step was using pumps with higher interference for a better seal and lower lift to reduce costs. Finally, two other modifications were

introduced: a change in elastomer for the efficiency issues and charge pumps for higher sand cuts.

 PCP Basic Principles

PCP systems are comprised basically by the surface equipment, the progressing cavity pump itself, the sucker rod string and

the production tubing, plus other bottom and surface minor accessories. Usually the stator is connected to the end of thetubing string while the rotor is connected to the sucker rod string. The energy required for pumping (torque and rotation) is

transmitted from the surface equipment through the rod string to the pump.

The PCP is a positive displacement pump that has two parts: the stator and the rotor. The rotor is the only moving part of the

 pump and is made of chrome coated high resistance steel and has “n” lobes. The stator is the static component, made from asteel tube that has been injected high density polymer (elastomer) shaped in double helix (“n+1” lobes). The most common

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Figure 3 – Left: Abrasion/Erosion Damage; Right: Corresponding Pump Test

Figure 4 – Left: Checked Chrome Coating; Right: Burnt Out Elastomer

 Elastomer types and their applications

Elastomers are amourphous polymers above their glass transition temperature with highly elastic behavior. The most popular

in downhole applications are nitrile and hydrogenated elastomers.

 Nitrile elastomers are the result of the copolymerization of butadiente and acrylonitrile (ACN) and are classified in mediumnitrile (25% to 35% ACN) and high nitrile (35% to 45% ACN). Acrylonitrile improves oil resistance while butadiene

influences the elastic behavior. Hydrogenated elastomers have a higher degree of saturation which improves resistance to

heat and hydrogen sulfur (H2S).

Produced fluids and bottomhole temperature can harm the elastomer. Interaction with produced fluids can cause swelling,

softening, contraction, hardening and bubbles. Swelling goes in hand with softening and is usually the result of theinteraction with light oil with high aromatics content. Some additives such as amine based corrosion inhibitors can also cause

softening. Low molecular weight solvents and paraffinic oils can cause contraction. H2S post vulcanizes the elastomer

changing its mechanical properties. When elastomers exposed to carbon dioxide are suddenly depressurized, bubbles are

formed.Pumps loose efficiency in abrasive applications due to elastomer wear. Wear rate dependes on the abrasives concentration,

 particles size and hardness, fluid velocity and pump interference. Choosing the right materials and optimizing the design

reduces the wear rate. Softer elastomers with high mechanical properties should be used. One of the key properties is

resiliency, which is the ability that an elastomer has to deform and return to its original shape.

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Table 1 – Type of elastomers and its properties

 Elastomer Compatibility Analysis

Increase of abrasion/erosion failures lead to analyize other elastomers available, in search of one with better mechanical

 properties. Elastomer compatibility analyses were necessary to verify that the main properties could survive bottomhole

conditions. These analyses were done at the beginning of the field life, but they had to be repeated since the produced fluids

characteristics could have changed since then.Elastomer compatibility can be evaluated in the lab or the field. In this case both were done simultaneously and then followed

 by a pilot test that started with 10 wells.

 Lab Analysis

The lab analysis consists in submerging elastomer probes in cylinders filled with the produced fluid. These cylinders are

 placed in an agitanting autoclave that is pressurized and heated to pump discharge conditions. Before the test each probed is

weighted in air and in water and has its hardness measured. The same properties are measure within one, five, ten, fifteen,thirty and forty five days to evaluate their evolution in time.

Three elastomers were tested and compared: compound 3, high nitrile historically used in this field; compound 1, medium

nitrile with better mechanical properties and compound 2, medium nitrile with better chemical properties. The test was only

carried out for 15 days since there were no significant variations between the properties measured on the eleventh and

fifteenth day.

Figure 5 – Lab Analysis, % Swelling Evolution

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Figure 6 – Lab Analysis, Hardness Evolution  

 Field Analysis

When sampling a well there is always loss of light components due to their volatilization. That is why in the field analysis the

 probes are placed directly in the production line. The downside is the temperature amplitude between day and night. In this

case the test took place during the summer and the surface temperature can be assumed equal to bottomhole temperature (35-38 °C). The next figure shows the bypass in the production line used to place the probes.

Figure 7 – Bypass line with three probes and a purge valve

The following figures show the evolution of hardness and swelling obtained in the field test.

Figure 8 – Field Analysis, % Swelling Evolution

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Figure 9 – Field Analysis, Hardness Evolution 

Since the results from lab and field analyses show similar trends they are assumed to be valid. Based on this results

Compound 1 was chosen for the pilot test of ten wells.

 Pilot Test Analysis – Interventions

Based on lab and field results analysis, it was decided to do a pilot test with medium nitrile pumps. The medium nitrile pumps were installed depending on the wells that were intervened, its associated problems and models availabilty. The first

ten wells exceeded expectations, and that is why by the end of 2012 there were twenty two wells with medium nitrile pumps.

Figure 10 shows the evolution of flush-by interventions. They are subclassified as General Flush-by, Sand Related Flush-by

(loss of production) and Sanded Pump Flush-by. This subclassification is necessary to identify sand related failures. It is alsodue mentioning that the improvement is also associated with the reduction of produced sand. The results are presented as a

Flush-by Index, calculated as annualized flush-by interventions per well.

Figure 10 – Flush-by Index Evolution

The next figure shows the evolution of sand related flush-by (sanded pump and loss of production) in the wells with medium

nitrile pumps.

0

50

100

150

200

250

300

350

400

450

500

0

0.5

1

1.5

2

2.5

3

3.5

4

4.5

5

2008 2009 2010 2011 2012*

   W   e    l    l   s

   F    l   u   s    h   B   y   I   n    d

   e   x

General Flush By Sand Related Flush By Sanded Pump Flush By Wells

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Figure 11 – Flush-by Index Evolution in wells with medium nitrile pumps

Finally, the flush-by index comparison is made for the same well with high and medium nitrile. The reduction of the index isremarkable.

Figure 12 – Flush-by index comparison per well

 Pilot Test Analysis – Pump Efficiency 

 Next figure compares the efficiency for the same well with high and medium nitrile pumps. By definition the efficiency takes

into account operating velocity and bottomhole pressure. All the efficiencies were calculated at 300rpm to make them

comparable. On average, the efficiency for medium nitrile pumps is higher than for high nitrile pumps.

0

2

4

6

8

10

12

14

16

18

20

High Nitrile Index M edium Nitrile Index

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Figure 13 – Efficiency comparison for high and medium nitrile pumps

Charge PCPs

This system could be simply described as two PCPs separated by a slotted nipple. The bottom pump is the charge pump itself

and has high displacement and low lift. The upper or main pump has low displacement and high lift. The charge pump

recirculates fluid since its displacement is three to four times that of the main pump.

The slotted nipple has to be at least 9 feet long, to avoid excessive stress on the rotors and pony rods. The minor diameter ofthe charge pump is smaller than that of the main pump while the pitch of the charge pump is always larger than that of the

main pump. The rotor of the charge pump has to pass through the stator of the main pump, which makes this dimensionalcompatibility mandatory.

When handling sand the first objective is that it enters the pump, in order to produce it and avoid settling in the rathole. The

charge pump has a paddle rotor which stirs the fluid in the pump suction helping the sand enter the pump. This type of rotor

is longer than traditional ones and has its bottom part machined in such a way that it ressembles a shovel. This extended partrotates inside a slotted tagbar stirring the fluid and keeping the sand suspended.It was mentioned earlier that the charge pump has three times the capacity of the main pump. This means that there is extra

fluid that needs to escape, and that is what the slotted nipple between the pumps is for. This recirculation of fluid increases

the velocity in the casing-tubing annulus and in the casing itself, causing better agitation, reducing sand settling and also

reducing sand total percentage in case of a sand slug.To avoid sand settling the pump suction velocity has to be higher than the annulus velocity. Once the sand particles go

through the charge pump the goal is to avoid settling in the pump discharge, for which tubing velocity has to be higher than

sand settling velocity.The next figure illustrates the charge pump system and how the fluid flows.

0

10

20

30

40

50

60

70

80

90

100

    E     f     f    i   c    i   e   n   c   y     (    %     )

    @ 

    3    0    0   r   p   m

High Nitrile Efficiency Medium Nitrile Efficiency

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Figure 14 – ChPCP Configuration and Fluid Flow 

Sand Settling Velocity Analysis

Sand settling velocity is calculated using the following equations:

   .    ………………………………………………………………………………………………….. (1)        2 ……………………………………………...………………………………………………………… (2)    ..     500 …………………………………………..………………………………………………………… (3)

  0.44   500 …………………………….……………………………………………………………………… (4)      ………………………………………………………………………………………………………………… (5)Where:Vs= Settling velocity (m/s)

D p= Particle diameter (mm)= Fluid density (kg/m3)= Sand density (kg/m3)CD= Resistance coefficient

 NRe= Reynolds number

 = Fluid viscosity (cp)

Several wells were sampled in order to quantify the relative percentages of the different grain sizes. The results are presented

in Table 1. Dispite being 0.4mm the average size, 1.7mm was used for the calculations since this represented the most critical

operating condition. ASTM Mesh N° Size in Microns wt% Method

40 2380 0.1 ASTM D-422

60 1680 0.3 ASTM D-422

80 1000 1.6 ASTM D-422

100 810 11.08 ASTM D-422

200 420 82.83 ASTM D-422

325 297 3.99 ASTM D-422

Table 2 – Grain Size Analysis

The following tables show the input data for CoHS-1018, the first well to have a charge pump installed.

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Input Data Model OD (in) ID (in) Areas (in

2) Displacement

(m3/d/rpm)

Efficiency (%)OD ID

Casing 5,5" - 15,5 lb/ft 5.50 4.95 - 19.24

Tubing 2 7/8" J55 - 6,5 lb/ft 2.88 2.44 6.49 4.68

Sucker Rod 7/8" Grade D 0.88 - 0.60 -

Main Pump 10-1600 NBRA 3.50 - 9.62 - 0.10 Not tested

Charge Pump 32-200 NBRA 3.50 - 9.62 - 0.32 95

Tagbar/Suction 2 7/8" Slotted 3XL 2.88 2.44 6.49 4.68Torque anchor TX5-2 4.00 2.44 12.57 4.68

Table 3 – Input Data for CoHS-1018

 Annulus Areas (in2)

Casing-Tubing 12.75

Casing – Pump 9.62

Casing- Tagbar 12.75

Tubing – Sucker rod 4.08

Table 4 – Annulus Areas

Settling velocity was calculated based on fluid properties and data from tables 2 and 3, and is presented in the next table:

Settling Velocity (m/s)

Fluid °API 17

Oil Cut 55

Sand Density (kg/m3) 2650

Fluid Density (kg/m3) 974

Fluid Viscosity (cp) 210

Reynolds Number 0.1

Resistance Coefficient (CD) 240

Settling Veloci ty (m/s) 0.0126

Table 5 – Settling Velocity

Conventional Pump Velocity Analysis

RPMSuction

Pressure(psi)

DischargePressure

(psi)

Differential

Pressure (psi)

Efficiency

%

Flowrate

(m3/d)

TubingVelocity

(m/s)

Casing-Tubing Annulus

Velocity (m/s)

CasingVelocity

(m/s)

50 88 987 899 42.6 2.1 0.0094 0.0156 0.0020

100 88 1014 926 69.5 7.0 0.0306 0.0224 0.0065

150 88 1041 953 78.5 11.8 0.0518 0.0292 0.0110

200 88 1067 979 82.9 16.6 0.0729 0.0360 0.0155

250 88 1094 1006 85.6 21.5 0.0941 0.0427 0.0199

300 88 1121 1033 87.4 26.3 0.1153 0.0495 0.0244

350 88 1148 1060 88.6 31.1 0.1364 0.0563 0.0289

Table 6 – Conventional Pump Velocity Analysis

In the case of CoHS-1018 the 10-1600 conventional pump needs to operate at least at 150 rpm to be above sand settling

velocity in the three zones (zone 1: tubing, zone 2: casing-tubing annulus, zone 3: casing).

Charge Pump Velocity Analysis

RPMSuction

Pressure(psi)

DischargePressure

(psi)

DifferentialPressure

(psi)

Efficiency(%)

Main PumpFlow Rate

(m3/d)

ChargePump FlowRate (m3/d)

TubingVelocity

(m/s)

Casing/Tubing Annulus

Velocity (m/s)

CasingVelocity

(m/s)

50 74 956 882 44.8 2.2 15.2 0.010 0.031 0.012

100 70 991 921 69.8 7.0 30.4 0.031 0.046 0.022

150 66 1027 961 78.1 11.7 45.6 0.052 0.060 0.032

200 62 1064 1002 82.2 16.4 60.8 0.072 0.075 0.041

225 60 1083 1023 83.5 18.8 68.4 0.083 0.082 0.046

250 59 1102 1043 84.5 21.1 76.0 0.093 0.090 0.051

300 56 1139 1083 86.1 25.8 91.2 0.114 0.105 0.061

350 53 1178 1125 87.2 30.5 106.4 0.134 0.119 0.071

Table 7 – Charge Pump Velocity Analysis

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The next figure illustrates the zones where the velocity is analyzed:

1.  Tubing velocity (not considered since it is the same for both cases)2.  Tubing-casing annulus velocity3.  Casing velocity

Figure 15 – Zone Analysis

The results from tables 5 and 6 are shown in the next figures for zones 2 and 3. 

Figure 16 – Casing/Tubing annulus velocity comparison 

0.000

0.020

0.040

0.060

0.080

0.100

0.120

0.140

0 100 200 300 400

   V  e   l  o  c   i   t  y ,  m

   /  s

RPM

ChPCP Conventional PCP

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Figure 17 – Casing velocity comparison

In the previous figures it can be seen that the velocity in both zone 2 and zone 3 for the charge pump is almost three times

that of the conventional pump.

Results Analysis

On August 26th 2010 CoHS-1018 became the first well to have a ChPCP installed. Results are compared for wells CoHS-

1018, ECN-0164 and PP-0110, although seven systems have been installed so far (wells CoHS-1018, CoHS-1020, CoHS-

2007, ECN-0164, ECN-0264, ER-0006 and PP-0110). These three wells had stable operating parameters and had nodisturbances that could cause misleading conclusions. In the next figure is the comparison of the annualized flush-by index

(N° Flush-by/well/year).

Figure 18 – Annualized Flush-by index comparison

The other wells were studied independently since their operating conditions changed radically after installation or operated

from the beginning with ChPCP (CoHS-1020). In the case of CoHS-1020 the comparison is made against its neighbours who

 produce from the same levels and have conventional pumps.

0.000

0.010

0.020

0.030

0.040

0.050

0.060

0.070

0.080

0 100 200 300 400

   V  e   l  o  c   i   t  y ,  m

   /  s

RPM

ChPCP Conventional PCP

0.0

5.0

10.0

15.0

20.0

25.0

30.0

CoHS-1018 ECN-0164 PP-0110

Conv PCP Flush-by Index Charge PCP Flush-by Index

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Figure 19 – Flush-by index por CoHS-1020 and its neighbours

An individual analysis is presented below for ER-0006, ECN-0264 and CoHs-2007 since each well had its own peculiarities.

ECN-0264: this well was perforated in 2010 and it was put straight in production with a ChPCP. It stopped producing afteronly six days in operation. The well was pulled and the main pump came out with its elastomer completely vulcanized. In the

failure analysis it was concluded that since the slotted nipple was above the perforations all the gas produced went through

the main pump, causing it to overheat due the low capacity of the gas to dissipate heat. This shows that both conventional and

ChPCPs have the same issues when it comes to gas handling. Nevertheless there are successful experiences in high GVFwells where the charge pump precompresses the gas (Robles et al. 2011).

CoHS-2007: this well was perfortated in 2012 and after a series of problems with conventional PCPs a ChPCP was installed.

At the start up of the ChPCP the well did not produce. Water was injected through the annulus with negative results. The

 pump was pulled and again the main pump elastomer was vulcanized. The root cause of this failure has not yet been

determined and this case is still undergoing analysis.

ER-0006: the ChPCP was installed on 5 November 2012, so at the moment of writing this paper there is not enough

information available for analysis.

Despite having experience with conventional PCPs, the ChPCPs have their own learning process related to design,installation and operation. As with every other artificial lift system it is extremely important the design of the bottom hole

assembly and the analysis of the produced fluid properties.

Conclusions

1.  Using medium nitrile pumps reduced on average five times the number of interventios with flush-by per well. Thishad a direct impact on production increase and intervention cost reduction.

2.  Higher efficiency was expected for medium nitrile due to its enhanced mechanical properties. This is translated into

lower operating velocities, with a positive impact on tubing and rod wear.3.  Medium nitrile pumps installation started only two years ago, so it is still too early to see if there is an increase in

 pump runlife.4.  Charge Pumps proved to be an alternative production system for high sand cut wells was found (4-5% continuous

and up to 25% slugs) that also reduces by half flush-by interventions due to sanded pump. Velocities in the critical

zones are three times higher, reducing sand settling and its associated issues.5.  Both charge and conventional PCPs cannot be installed in wells with intermittent production neither be operated on-

off. When producing sand the best practice is to have continuous operation.

6.  In gas producing wells both pumps and its slotted nipples need to be installed below perforations to avoid prematurefailure. Though there are case studies where the charge pump was used as a precompressor or gas separator in

horizontal wells, this was not the case.7.  With Charge Pumps well testing duration is reduced 12 to 16 hours, since this system is capable of handling a larger

sand percentage than conventional PCPs.

0.0

2.0

4.0

6.0

8.0

10.0

12.0

14.0

CoHS-2003 CoHS-2002 CoHS-1021 CoHS-1020

Flush-by Index Average Neighbours

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8.  During the end of 2012 and the course of 2013 four more charge pumps were installed, but this time using mediumnitrile. The behavior of these wells is under analysis, in order to determine if the combination of technologies yields

 better results.

Acknowledgements

The authors would like to thank everyone in Pluspetrol SA and Weatherford Intl. who supported these projects from the beginning and helped in its implementation.

References

Cevallos, Vaamonde, Rivero, Rojas, Joo Kim, Galarza and Legarreta 2011. Exploration and development of a heavy oil field

in Río Colorado, northwest margin Neuquen Basin, Argentina (in Spanish) presented at IAPG Hydrocarbon

Exploration and Development Seminar, Mar del Plata, Argentina, 8-11 November 2011.

Montiveros, Echavarría, Sáez, Ortiz Best and Fernández 2012. Completion and production techniques for sand producing non

consolidated reservoirs from Centenario formation (in Spanish), presented at IAPG Enhanced Oil Recovery Seminar

Mendoza, Argentina, 19-21 September 2012.

Robles, Perez, Bettenson and Noble 2011. Design and application of charge PCP systems in high GVF heavy oil wells. PaperSPE 153038, presented at SPE Progressing Cavity Pumps Conference, Edmonton, Canada, 12-14 September 2010.

Motiveros, Echavarría and Briozzo 2013. Benefits of PCP Charge Pumps applied to sand producing reservoirs. Paper SPE

165077, to be presented at SPE Artificial Lift Conference, Cartagena, Colombia, 21-22 May 2013.