SPE 172686Number

PCPs Coming of Age as a Viable Artificial Lift Solution for Low API Crude Fields Soham Agarwal, SPE, Avi Aggarwal, SPE, Indian School of Mines; Avinav Kumar, SPE, Oil and Natural Gas Corp. Ltd.

Copyright 2015, Society of Petroleum Engineers

This paper was prepared for presentation at the SPE Middle East Oil & Gas Show and Conference held in Manama, Bahrain, 8–11 March 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 written consent of the Society of Petroleum Engineers is prohibited. Permission to reproduce in print is restricted to an abstract of not more than 300 words; illustrations may not be copied. The abstract must contain conspicuous acknowledgment of SPE copyright.

Abstract

Majority of the Indian Oil Fields have gone well past the age of self-flow, with only a very few select wells currently producing crude utilizing the natural reservoir energy. It is a well-documented fact that the age of easy, light oil has passed and that, most of the new discoveries being made are those of either heavy or ultra-heavy crude oil types.

SRPs, ESPs, Jet pumps, Gas lift are the various modes of artificial lift currently under employment. However, all these methods fail when heavy oils are encountered. In such cases, these methods of artificial lift fail to provide the requisite lift for the crude to reach the surface. However, the Progressive Cavity Pumps (PCPs) have found great utility under conditions of heavy crude production. The spiral motion of the Pump cavity from suction to discharge causes jerk-free motion of the crude.

PC Pumps have distinctive advantage over the other methods, when heavy crudes along with significant sand cuts are to be produced. PC Pumps are also used on a large scale for de-watering of CBM wells.

In this paper, an extensive review of the available literature was done to study PC Pumps and the various advancements achieved through the years. Artificial lift selection methods were investigated and a comprehensive procedure enlisted to select the right type of lift which best suits the field/well.

Introduction

Artificial lift methodology is used to lower the producing bottom-hole pressure (BHP) so that a production rate is obtained from the formation through the producing well. This may be performed in many ways:

With a positive-displacement down hole pump, such as a beam pump or a progressive cavity pump (PCP), to lower the flowing pressure at the pump intake.

With a centrifugal pump as a part of an Electrical submersible pump (ESP). With a gas lift system wherein the density of the fluid in the tubing is lowered and expanding gas helps to lift the

fluids.

Generating flow from a well which is not flowing or to increase flow from an already well are two basic purposes of artificial lift. Most oil wells require artificial lift at some point in the life of the field, and many gas wells benefit from artificial lift to take liquids off the formation so gas can flow at a higher rate.

The major forms of artificial lift are:

Sucker-rod (beam) pumping Electrical submersible pumping (ESP) Gas lift and intermittent gas lift

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Reciprocating and jet hydraulic pumping systems Plunger lift Progressive cavity pumps (PCP) (Vogel, 1968) (Babu et. al., 1989) (Bennett, 1980)

Choosing the best method of artificial lift system from the wide range of available methods is important considering location, depth, estimated production, reservoir production, reservoir properties, and other factors. This will be discussed in further detail in the next topic. (Lea et. al., 1997) (Lia et. al., 1997)

Society of Petroleum Engineers (SPE) estimates that more than 80% of the world’s oil wells are on some kind of artificial lift. Artificial lift is required for those wells which have insufficient energy to push oil up to the surface. By popular estimates, about half of all currently known oil reserves in the world are of the unconventional type, with viscosity ranging from heavy oil to near-solid bitumen. These oils do not flow unless they are heated. The viscosity of oils is greatly sensitive towards heat and decreases with increasing temperature. Many thermal recovery methods, such as Steam Assisted Gravity Drainage (SAGD), Carbon Storage and Sequestration (CSS) and others, are used to inject heats into the reservoirs, decreasing the oil viscosity which enables us to utilize artificial lift methods to then lift the heated oil to the surface. Progressive Cavity pumps are best suited in such conditions to drive heavy crude up to the surface.

The name progressive cavity pumps (PCP) is derived from the unique positive displacement pumps that evolved as a result of tweaking in the design of helical gear pumps, first developed by Rene Moineau in the late 1920s. These pumps are most commonly known as the Progressive Cavity (PC) pumps. However, they are also referred to as screw pumps or Moineau pumps. The use of PC Pumps as a means of artificial lift is increasing being more suitable, when compared to other artificial lift methods, for a range of challenging situations like heavy oil, high sand production, high GOR, directional or horizontal wells. (Moineau R.J.L., 1932) (Moineau R.J.L., 1937)

Artificial Lift Selection

Deciding the most appropriate artificial lift technology for a well is very crucial for optimum well performance. This task is performed by taking into consideration various factors ranging from reservoir properties to operational constraints. The candidate systems are first screened and then the most suitable lift system is chosen. In the Table 1 the artificial lift systems are compared with respect to popular operational considerations.

Sucker Rod

Pumping

Progressing Cavity Pumping

(PCP)

ESP

HydraulicReciprocatin

gPumping

HydraulicJet

Systems

Gas Lift (Continuous

Flow)

Gas Lift (Intermitte

nt)Plunger

Lift

Efficiency (output

Hydraulic horsepower divided by

input hydraulic

horsepower)

Excellent total system efficiency. Full pump fillageefficiencytypically about50 to 60%feasible if well is not over-pumped.

Excellent: may exceed rod pumps for ideal cases. Reportedsystem efficiency50% to 70%.More operating data needed.

Good for high rate wells but decreases significantly for <1,000 BFPD. Typically total system efficiency is about 50% for high rate well, but for < 1,000 B/D, efficiency typically is <40%.

Fair to good: not as good as rod pumping owing to GLR, friction, and pump wear. Efficienciesrange from 30% to 40% withGLR>100; may be higher with lower GLR.

Fair to poor.Maximum efficiency only 30%. Heavily influenced by power fluid plus production gradient. TypicalOperating efficiencies of 10% to 20%.

Fair: increases forwells that requiresmall injectionGLR's. Low for wells requiring high GLR's.Typicalefficiencies of20% but range from 5% to 30%.

Poor: normally requires a high injection gas volume/barrel fluid. Typical lift efficiency is 5% to 10%; improved with plungers.

Excellent for flowing wells. No input energy required because it uses the energy of the well. Good even when small supplementary gas is added.

SPE Number 3

Flexibility

Excellent: can alter stroke speed and length, plunger size, and run time to control production rate.

Fair: can alter speed. Hydraulic unit provides additional flexibility but at added cost.

Poor: pumps usually run at a fixed speed. Requires careful sizing. VSD provides more flexibility but added costs.Time cycling normally avoided. Must size pump properly.

Good/excellent:Can vary power fluid rate and speed of down-hole pump. Numerous pump sizes and pump/engine ratios adapt to production and depth needs.

Good to excellent: power fluid rate and pressure adjusts the production rate and lift capacity.Selection of throat and nozzle sizes extends range of volume and capacity.

Excellent: gas injection rate varied to change rates. Tubing needs to be sized correctly.

Good: must adjust injection time and cycles frequently.

Good for low-volume wells.Can adjust injection time and frequency.

Operating costs

Very low for shallow tomedium depth (<7500 ft) land locations withlow production«400 BFPD).

Potentially low, but short run life on stator or rotor frequently reported.

Varies: if horsepower is high, energy costs are high. High pulling costs result from short run life. Often repair costs are high.

Often higher than rod pumps even for free systems.Short run life increases total operating costs.

Higher power cost owing toHorsepower requirement. Low pump maintenance cost typical with properly sized throat and nozzle.

Well costs low. Compression costs vary depending on fuel cost and compressor maintenance.Key is to inject as deeply as possible with optimum GLR.

Same as continuous-flow gas lift.

Usually very low.

Reliability

Excellent: run time efficiency >95% if good operating practicesare followed and if corrosion, wax, asphaltene, solids, deviations,etc., are controlled.

Good: normally over-pumping and lack of experience decreases run time.

Varies: excellent for ideal lift cases; poor for problem areas.Very sensitive to operating temperatures and electrical malfunctions.

Good with a correctly designed and operated system. Problems or changing well conditions reduce down-hole pump reliability.Frequent downtime results from operational problems.

Good with proper throat and nozzle sizing for the operating condition. Must avoid operating in cavitation range of jet pump throat; related to pump intake pressure. More problems ifpressures> 4,000 psig.

Excellent if compression system properly designed and maintained.

Excellent if there is an adequate supply of injection gas and an adequate low-pressure storage volume for injection gas.System must be designed for the unsteady gas flow rates.

Good if well production is stable.

System (total)

Straightforward and basic procedures

Simple to install and operate. Limited

Fairly simple to design but requires

Simple manual or computer design

Computer design program typically

An adequate volume, high· pressure, dry, noncorrosive

Same as continuous-flow gas lift.

Individual well or system. Simple to

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to design, install, and operate' following API specifications and recommended practices. Each well is an individual system.

proven design, installation, and operating specifications and procedures. Each well is an individual system.

good rate data. System not forgiving.Requires excellent operating practices. FollowAPI recommended practices in design, testing, and operation.Typically each well is an individual producer using a common electric system.

typically used. Free pump easily retrieved for servicing. Individual well unit very flexible but extra cost.Requires attention. Central plant more complex; usually results in test and treatment problems.

used for design. Basic operating procedure needed for down-hole pump and well site unit.Free pump easily retrieved for onsite repair or replacement. Down-hole jet often requires trial and error to arrive at best/optimum jet.

and clean gas supply source is needed throughout the entire life. System approach needed.Low backpressure beneficial. Good data needed for valve design and spacing. API specifications and design/operating recommender practices should be followed.

design, install, and operate.Requires adjusting and plunger maintenance.

Table 1 - Artificial-Lift Design Considerations and Overall Comparisons (Clegg et. al., 1993)

Selection of artificial left systems can be very time consuming when working on projects involving large number of wells. So, production engineers are coming up with workflows to expedite the process and make informed decisions. In Figure 1a similar workflow termed as Matrix Classification enables simplification of the selection procedure and helps the operators to pick the lift technology suitable for each well based on well – reservoir considerations. For better results the selection from Table 1 and Figure 1 can be correlated, thus delivering the best solution to the operator. It can be clearly noted from the above two classifications that PCPs are suitable for application in fields with low API crude having high/moderate solid production and high water cut. When augmented with its various other features PCP becomes an appropriate technology for installation in wells producing heavy crude.

History

PC pumps were initially extensively used to transfer fluids for industrial and manufacturing purposes with some attempts to use them for the surface transfer of oilfield fluids. However, it was not until after the development of synthetic elastomers and adhesives in the late 1940s that PC pumps could be applied effectively in applications involving petroleum-based fluids. Except for several limited field trials, it was not until the late 1970s that a concerted effort was made to use PC pumps as a method of artificial lift for the petroleum industry. Over the past two decades, with the technical contributions and persistence of many individuals and companies, PCP systems have experienced a gradual emergence as a common form of artificial lift method. Although precise numbers are difficult to obtain, it is estimated that more than 50,000 wells worldwide currently are being produced with these systems as on 1990-2000. (Cholet H., 1997) (Lea et. al., 1988) (Gaymard et. al., 1988) (Matthews et. al., 1993) (Wright et. al., 1993)

Principle of operation of a PC Pump

A progressive cavity pump consists of a single helical gear (rotor which rotates inside a double helical elastomeric gear (stator) of the same minor diameter and twice the pitch length as shown in figure 2. (Saveth et. al., 1989)

As the rotor rotates eccentrically within the stator, a series of sealed cavities form 180 degrees apart which progress from the suction to the discharge ends of the pump. As one cavity diminishes, another is created at the same rate resulting in a constant non-pulsating flow. (Saveth et. al., 1989) (Dillon et. al., 1983)

SPE Number 5

Figure 1: Selection of Appropriate Technology (Petrov et. al., 2010)

Figure 2: Rotor and Stator Major and Minor Diameters (Saveth et. al., 1989)

The total cross-sectional area of the cavities remains the same regardless of the position of the rotor in the stator as shown in Figure 3. (Saveth et. al., 1989)

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Figure 3: Constant cavity cross sectional area (Saveth et. al., 1989)

The progressing cavity pump overcomes pressure because it has a complete seal line between the rotor and stator for each cavity. The pressure capabilities in the pump are based on the number of stages and the number of times the seal lines are repeated. Normally a stage is designed and manufactured to be 1.1 to 1.5 times the pitch length of the stator. The reason for this is to insure a proper seal between the rotor and stator to achieve the desired psi/stage rating in order to sustain a desirable operating life. Figure 4 shows this relationship between the rotor and stator pitch lengths. (Saveth et. al., 1989)

Figure 4: Rotor/Stator pitch relation (Saveth et. al., 1989)

By increasing the number of seal lines or stages the pressure capability of the pump is increased allowing it to pump from deeper depths. As pressure increases for the same number of stages and speed the flow rate decreases. The reduction in flow rate caused by pressure higher than atmospheric is called slip. (Saveth et. al., 1989)

All rotary positive displacement pumps experience some slippage as a result of differential pressure between the suction and discharge ends. The amount of slip is determined by the pressure and is independent of speed. It is however dependent upon the number of seal lines or stages, the viscosity of the fluid being pumped, and the compression fit between the rotor and stator. The curve in Figure 5 graphically shows the definition of slip. (Saveth et. al., 1989).

Figure 5: Graphic definition of slip (Saveth et. al., 1989)

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Figure 6: Viscosity effect on slip (Saveth et. al., 1989)

Figure 7: Compression fit effect on slip (Saveth et. al., 1989)

Figures 6 and 7 shows the effects of fluid viscosity and compression fit respectively on slip. In Figure 5 one can see the effects of fluid viscosity in relation to slip and flow. The higher the viscosity, the lower the slip at any given pressure. This is due to the fact that the increased viscosity will tend to resist flow in any direction. The higher viscosity fluid will not flow easily into the cavity causing cavitation to occur, thus a decrease in displacement per revolution. This decrease in flow into the cavity is evident in the lower flow rate at 0 psi for the higher viscosity fluids. The higher viscosity fluids do create increased frictional line losses in the production string and flow line. This causes higher line pressure which in turn will bring about higher differential pressure and additional slip. Figure 5 shows the effect of rotor/stator fit on slip. As the compression fit between the rotor and stator decreases, the slip within the pump increases with an increase in differential pressure; by design, the compression fit is constant and changes only from wear of the stator and/or rotor or swell of the elastomer. (Saveth et. al., 1989)

Applications of PC Pump systems

High overall system energy efficiency, typically in the 55 to 75% range. Ability to produce high concentrations of sand or other produced solids. Ability to tolerate high percentages of free gas. No valves or reciprocating parts to clog, gas lock, or wear. Good resistance to abrasion & low internal shear rates (limits fluid emulsification through agitation). Relatively low power costs and continuous power demand (prime mover capacity fully utilized). Relatively simple installation and operation & requires low maintainance Low profile surface equipment. Low surface noise levels. (Clegg et. al., 1993) (Saveth et. al., 1983) (Eson R., 1997)

Limitations of PC Pump systems

PCP systems, however, also have some limitations and special considerations:

Limited production rates (maximum of 800 m3/d [5,040 B/D] in large-diameter pumps and much lower in small-diameter pumps).

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Limited lift capacity (maximum of 3000 m [9,840 ft]). Note that the lift capacity of larger displacement PC pumps is typically much lower.

Limited temperature capability (routine use to 100°C [212°F], potential use to 180°C [350°F] with special elastomers).

Sensitivity to fluid environment (stator elastomer may swell or deteriorate on exposure to certain fluids, including well treatment fluids).

Subject to low volumetric efficiency in wells producing substantial quantities of gas. Sucker rod strings may be susceptible to fatigue failures. Pump stator may sustain permanent damage if pumped dry for even short periods. Rod-string and tubing wear can be problematic in directional and horizontal wells. Most systems require the tubing to be pulled to replace the pump. Vibration problems may occur in high-speed applications (mitigation may require the use of tubing anchors and

stabilization of the rod string). Paraffin control can be an issue in waxy crude applications (rotation as opposed to reciprocation of the rod string

precludes use of scrapers for effective wax removal). Lack of experience with system design, installation, and operation, especially in some areas.

Many of these limitations continue to change or be alleviated over time with the development of new products and improvements in materials and equipment design. If configured and operated properly in appropriate applications, PCP systems currently provide a highly efficient and economical means of artificial lift. (Clegg et. al., 1993) (Saveth et. al., 1983) (Eson R., 1997)

Major Advancements in PCP technology

1. Electrical Submersible Progressive Cavity Pump (ESPCP):

In order to tackle the poor solid handling of ESPs and the problem of rod/tubing systems in horizontal operations, a hybrid pumping technology was developed utilizing the best of both ESPs and PCPs. Being a rodless system the friction losses at tubing and rod are eliminated. The configuration of ESPCP system is shown in Figure. The ESP motor is a downhole drive system and according to the power required its sizing is determined. The gear reducer installed above the ESP motor reduces the speed and increase the torque available to PCP. The main function of seal is to restrict the entry of well fluids into the gear reducer and motor, thus isolating the conditioned motor oil (Taufan et.al., 2005). In ESPCPs a planetary gearbox is coupled with a standard ESP motor using a flex shaft. The eccentric rotation of the PCP is achieved by flex shaft which converts the concentric rotation of ESP motor (Krawiec et. al., 2008). This technology is gaining grounds for CBM dewatering and horizontal well applications with high solids production.

Figure 8: Basic Configuration of an ESPCP (Taufan et. al., 2005)

SPE Number 9

2. Metal PCP:

Thermal recovery projects involve high fluid temperature conditions but the elastomer stator of standard PCP can’t withstand temperatures above 320°F, thus making it an unfavorable choice (Beauquin et al., 2005). Similar is the case with light oil producing fields where the major composition of oil is Mono-Aromatics mostly comprising of Benzene, Toluene and Xylene (BTX). The BTX molecular structure makes it very reactive and it readily attacks the elastomer, making it swell and soften. BTX becomes more aggressive at higher temperatures complementing the fact that light oil is found in deeper and warmer reservoir (Jahn et al., 2013). Thus, to tackle these challenging situations recent developments in manufacturing process engineering have enabled the development of full metallic PCPs. For this hydroforming principle is utilized to manufacture the metal stator. The metal of both stator – rotor are chosen to have the same thermal expansion coefficient making it fully functional from 390°F till negative temperatures, while the use of metal instead of elastomer makes it resilient against BTX, H2S and other corrosive chemicals. Testing of metal PCPs on pilot wells jointly by PCM and Total have showed very promising results. Also, these pumps have same installation procedure while will offer low CAPEX and OPEX to end users (Beauquin et al., 2005).

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