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Benefits Of PCP Charge Pumps Applied To Sand Producing ReservoirsMariano Montiveros, Pluspetrol SA, Lucas Echavarria, Pluspetrol SA, María Briozzo, Weatherford Internacional de

 Argentina SA

Copyright 2013, Society of Petroleum Engineers

This paper was prepared for presentation at the SPE Artificial Lift Conference-Americas held in Cartagena, Colombia, 21-22 May 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

Heavy sandy fluids production is one of the biggest challenges for an artificial lift system. Progressing cavity pumping (PCP)

has always been the preferred method, but as sand cuts get higher a PCP by itself is not enough: this is when charge pumps

come into the picture.

This system consists of a main pump, which has high lift and low volumetric capacity; a charge pump which has low lift and

three times the capacity of the main pump and a perforated nipple between them. This arrangement provides higher suction

velocities reducing the deposition of solids in the rathole and the recirculation between both pumps helps keeping the

 perforations clean.

This study is based on the first experience in Argentina using charge pumps. The field is “Cerro Huanul Sur” and is located in

the Neuquen Basin. This system was installed in seven wells and this study covers the benefits and limitations of each case.

The design of the bottomhole assembly was tailored to the specific needs of each well. This included the analysis of fluid

 properties, well configuration and production history. The installations were carefully supervised and the performance tracked

using data logging and surveillance.

The completion of this type of wells is costly and time consuming since the sand cut has to be reduced to acceptable values.

Once in production, the typical problems are blocked suction, formation of sand bridges in the annular space between casing

and tubing, bridges in the tubing itself and sanded pump. In the conclusion this study will show how these issues were all

overcome; reducing completion time, the interventions of the well with a flush-by unit or a pulling rig and downtime, and

increasing pump run life.

Introduction 

The Corcobo Norte field and its neighbours, Jagüel Casa de Piedra, Cerro Huanul Sur, Puesto Pinto, El Renegado and

Gobernador 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 to

show 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 over

550 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% while

the permeability ranges from 0.5 to 4 Darcy, being the average 1 Darcy. The average height is 8m (26 ft) but intervals as high

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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.

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 producing

wells 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

 Development

As the field was developed new border zones were perforated and two meters height intervals were found. These new intervals

are heterogenous and even less consolidated than those from the central zones. Wells with larger useful intervals were also

found, but they required more perforations. The arise of these new challenges made it necessary to look for new production

alternatives based on the completion and production techniques used for these types of reservoirs   (Montiveros et al. 2012).

This is how Charge Progressing Cavity Pumps (ChPCP) came into the picture.

 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 the tubing

string while the rotor is connected to the sucker rod string. The energy required for pumping (torque and rotation) istransmitted 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 a

steel tube that has been injected high density polymer (elastomer) shaped in double helix (“n+1” lobes). The most common

geometry is 1:2, that is, one lobe rotor and two lobes stator.

By definition, in 1:2 geometries three closed cavities make one stage. The lift capacity (rated pressure) of the pump is a direct

function of the number of stages. Another concept associated to pump performance is the interference, which is the tightness

 between rotor and stator and depends on the elastomer swelling and the rotor diameter.

The cavities are independant spiral lenses created by the voids between the rotor and the stator, separated by the seal line.

Differential pressure across the pump distorts the seal line, resulting in fluid slippage from one cavity to the previous one. The

slippage is a function of the number of stages and the interference, and causes a loss of volumetric capacity (pump efficiency).

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 Problems Associated to Sand Handling

The main issues associated to sand handling, besides its effects on the elastomer and the erosive/abrasive action in the metallic

components (tubing and sucker rods), are:

  Restricted or blocked pump suction due to sand bridges and plugs in the tubing/casing annulus;

  Sand settling in the rathole that could lead to perforations blockage. This could restrict flow from the reservoir and

complicate the pulling of the bottom hole assembly. This is why the rathole of these type of wells is 50 to 70m depth

(164 to 230ft);

  Sand slugs cause torque peaks that can get the pump sanded;

  Sand bridges or plugs inside the tubing (tubing/sucker rods annulus) that restrict pump discharge and could even block it, leading to pump failure due to overpressure;

  Sand settling in the pump discharge in the event of a shut down;

  Surface lines blockage due to sand settling.

Though PCPs are the best option in terms of artificial lift methods for handling sand, the quest was finding a configuration that

was better at dealing with all the issues mentioned above.

Charge PCPs

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

the 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 dimensional

compatibility 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 part

rotates 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 reducingsand 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.

Figure 2 – ChPCP Configuration and Fluid Flow

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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 1 – Grain Size Analysis

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

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 4.68

Torque anchor TX5-2 4.00 2.44 12.57 4.68

Table 2 – 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 3 – Annulus Areas

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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 17Oil Cut 55Sand Density (kg/m3) 2650

Fluid Density (kg/m3) 974Fluid Viscosity (cp) 210Reynolds Number 0.1

Resistance Coefficient (CD) 240

Settling Velocity (m/s) 0.0126

Table 4 – Settling Velocity

Conventional Pump Velocity Analysis

RPM

Suction

Pressure(psi)

Discharge

Pressure(psi)

Differential

Pressure (psi)

Efficiency

%

Flow

rate(m

3 /d)

Tubing

Velocity(m/s)

Casing-Tubing

AnnulusVelocity (m/s)

Casing

Velocity(m/s)

50 88 987 899 42.6 2.1 0.0094 0.0156 0.0020100 88 1014 926 69.5 7.0 0.0306 0.0224 0.0065150 88 1041 953 78.5 11.8 0.0518 0.0292 0.0110200 88 1067 979 82.9 16.6 0.0729 0.0360 0.0155250 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 0.0244350 88 1148 1060 88.6 31.1 0.1364 0.0563 0.0289

Table 5 – 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/TubingAnnulus

Velocity (m/s)

CasingVelocity

(m/s)

50 74 956 882 44.8 2.2 15.2 0.010 0.031 0.012100 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 6 – Charge Pump Velocity Analysis

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

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Figure 3 – Zone Analysis

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

Figure 4 – Casing/Tubing annulus velocity comparison 

Figure 5 – Casing velocity comparison

0.000

0.010

0.020

0.030

0.040

0.050

0.060

0.070

0.080

0 50 100 150 200 250 300 350 400

   V  e   l  o  c   i   t  y

 ,  m   /  s

RPM 

ChPCP Conventional PCP 

0.000

0.020

0.040

0.060

0.080

0.100

0.120

0.140

0 50 100 150 200 250 300 350 400

   V  e   l  o  c   i   t  y ,  m   /  s

RPM 

ChPCP Conventional PCP 

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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 no disturbancesthat could cause misleading conclusions. In the next figure is the comparison of the annualized flush-by index (N° Flush-

 by/well/year).

Figure 6 – 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.

Figure 7 – 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 after

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

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 

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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ChPCPs have the same issues when it comes to gas handling. Nevertheless there are successful experiences in high GVF wells

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.  An alternative production system for high sand cut wells was found (4-5% continuous and up to 25% slugs) that alsoreduces 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.

2.  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.

3.  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.

4.  Well testing duration is reduced 12 to 16 hours, since this system is capable of handling a larger sand percentage than

conventional PCPs.

Acknowledgements

The authors would like to thank everyone in Pluspetrol SA and Weatherford Intl. who supported this project 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. Paper

SPE 153038, presented at SPE Progressing Cavity Pumps Conference, Edmonton, Canada, 12-14 September 2010.