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Electric Submersible Pumping Systems vs.

Long-Stroke Pumping Units: an Economical

Comparison in Lower-Volume Wells

A Production Optimization White Paper from Weatherford

Presented by Roman Molotkov, Technical Marketing and Sales Manager

E S P s v s . L o n g - S t r o k e P u m p i n g U n i t s - P a g e | 2

Abstract

OPEX Reduction in Wells Pumped by Electric Submersible Pump (ESP) Systems

In the oil field, conventional wisdom holds that the artificial-lift method of rod lift is suitable only for producing

flow rates of 200 STB/D or below and at pump setting depths greater than 4,000 ft. At flow rates greater than

200 STB/D, ESP systems represent the most common lift method, particularly for deep, high-water-cut oil wells.

This traditional view is now being challenged, thanks to the advent of long-stroke pumping units for rod-pump

wells. Because these units extend the operating envelope for rod lift, the use of long-stroke pumping units has

grown rapidly in recent years and been seen as a viable lift option in wells traditionally pumped by ESPs. In

deeper wells (i.e., those exceeding 4,000 ft), long-stroke pumping units routinely provide superior operating

efficiencies compared to ESPs, up to a production rate of 1,500 STB/D.

This paper reviews a field example in which production in a mature well declined to the point that the existing

ESP was oversized for the well. And because the pump was at risk for imminent failure, the operator needed to

select a replacement artificial-lift system that better suited the current well condition. This paper compares the

operating expenses (OPEX) for two replacement choices—a smaller-size ESP and a long-stroke pumping unit. The

comparison shows that operators will realize significant financial benefits by choosing the long-stroke pumping

system for this application, thanks to cost reductions in power, workovers, and inventory.

Introduction

The continued global demand for oil and gas compels operators to keep searching for new means of boosting

production from their wells. And whether a field has been in production for only a few months or several

decades, maximizing production typically means employing one of several artificial-lift methods.

As wells get deeper and water cuts rise, many operators rely on ESPs to bring produced fluids to surface at

desired flow rates. ESPs are an attractive choice due to their wide operating envelope and their ability to bring

higher production volumes to surface from greater well depths than conventional rod-pump systems. When

operated and maintained properly, ESPs have been shown to perform reliably in wells with high-volume lift

requirements; deep, hot and/or deviated wells; and waterfloods or high water-cut wells.

However, ESPs are not the right lift answer for every application and every well depth. In many cases, rod

pumping provides a more cost-efficient solution for low-rate ESP wells.

Long-stroke design drives efficiency

Long-stroke pumping units offer an alternative lift option that promises higher efficiencies than conventional

rod-pump units and better cost-effectiveness compared to ESPs in some applications. Like beam-pump systems,

long-stroke units utilize sucker rods and a downhole pump, but that is where the design similarities end. The

surface equipment is fundamentally different for the long-stroke unit, as the conventional pumpjack is replaced

with a vertical unit that is shipped and installed to the wellsite in one piece (Figure 1).


Figure 1

Long-stroke pumping unit

As its name implies, the long-stroke system has a longer stroke length compared to a beam-pumping unit and

operates at lower speeds—an average of 3.75 strokes per minute (SPM) vs. an average of 8 SPM. During a large

part of its pump cycle the long-stroke unit’s rod string moves at a relatively steady velocity, which results in

fewer acceleration-deceleration cycles and less stress on the equipment. The combined effect of constant

velocity and fewer strokes per barrel serve to increase the run lives of the pumping unit, downhole pump, and

the rod string.

The long-stroke unit has a lower torque requirement, thanks to the use of a sprocket with a shorter radius than

the distance between the saddle bearing and the horsehead on a conventional beam unit. The sprocket turns

faster than the crank on a conventional unit, thus enabling it to transmit power at a lower torque. This helps

extend the applicability of the long-stroke unit to a wider range of production rates and well depths compared to

beam-pump units.

The unit also provides simpler well servicing compared to a conventional beam unit. After disconnecting the

bridle and carrier bar from the polished rod, the long-stroke unit is rolled away from the wellhead without any

disassembly. After a workover is completed, the unit is rolled back into place, and the carrier bar is reconnected

to the polished rod.

E S P s v s . L o n g

The design features of the long-stroke unit provid

ESPs. The units produce similar flow rates to ESPs at greater depths, routinely being able to achieve up to 1,500

STB/D at 6,000 ft and 100 STB/D at 10,000 ft. In shallow wells, which are typical

stroke units can deliver production rates exceeding 4,000 STB/D.

The long-stroke pumping unit also provides greater operational efficiency than ESPs at similar depths, requiring

less power input and demonstrating greater tol

conditions. ESPs are prone to premature failures in cyclic operational conditions for the following reasons:

• Premature ESP Protector Failure: Cyclic operation causes thermal cycles and flexure cycles on

bag-type ESP protectors. Thermal and pressure cycles cause fluid movement within labyrinth

type protectors, which accelerates contamination of the motor oil, caus

thrust bearing and motor failure.

• ESP Motor Overheating: Motor cooling is highly dependent on the velocity of the fluid passing

the downhole motor. In cyclic operations ESP motors are prone to overheating due to increased

peak power requirements coupled with intermittent lower flow rates.

Another significant difference between ESP operations and the long

pump is more tolerant to high downhole temperature than the ESP.

ESP operation at

Figure 2 shows a number of generic ESP performance curves for flow rates between 200 and 2,000 STB/D. These

performance curves represent head and efficiency, and their lengths represent recommended operating ranges.

Figure 2 Generic ESP performance curves for flow rates between 200 and 2,000 STB/D

P s v s . L o n g - S t r o k e P u m p i n g U n i t s

stroke unit provide the ability to pump deep wells that were once reserved for


STB/D at 6,000 ft and 100 STB/D at 10,000 ft. In shallow wells, which are typically non-ESP applications, long

stroke units can deliver production rates exceeding 4,000 STB/D.

stroke pumping unit also provides greater operational efficiency than ESPs at similar depths, requiring

less power input and demonstrating greater tolerance to cyclic operations caused by changing reservoir


Premature ESP Protector Failure: Cyclic operation causes thermal cycles and flexure cycles on

type ESP protectors. Thermal and pressure cycles cause fluid movement within labyrinth

type protectors, which accelerates contamination of the motor oil, caus

thrust bearing and motor failure.

ESP Motor Overheating: Motor cooling is highly dependent on the velocity of the fluid passing


requirements coupled with intermittent lower flow rates.

Another significant difference between ESP operations and the long-stroke unit operations is that the sucker rod

pump is more tolerant to high downhole temperature than the ESP.

ESP operation at low and medium flow rates



eric ESP performance curves for flow rates between 200 and 2,000 STB/D

t r o k e P u m p i n g U n i t s - P a g e | 4

e the ability to pump deep wells that were once reserved for


ESP applications, long-

stroke pumping unit also provides greater operational efficiency than ESPs at similar depths, requiring

erance to cyclic operations caused by changing reservoir


Premature ESP Protector Failure: Cyclic operation causes thermal cycles and flexure cycles on

type ESP protectors. Thermal and pressure cycles cause fluid movement within labyrinth

type protectors, which accelerates contamination of the motor oil, causing imminent protector

ESP Motor Overheating: Motor cooling is highly dependent on the velocity of the fluid passing


requirements coupled with intermittent lower flow rates.

stroke unit operations is that the sucker rod




At flow rates below 1,000 STB/D, ESPs exhibit rather low efficiencies (less than 50% at the best efficiency point).

How do low efficiencies affect operations? Low efficiencies imply high power consumption and higher heat

generation, which lead to higher costs and lower run life. Due to changing well conditions, the ESP’s operating

point can deviate from the recommended operating range and settle within a very low efficiency zone, which

reduces run life even further.

Figure 3 Downhole view of the long-stroke pumping unit

Figure 4 Downhole view of the ESP system

Selecting an optimum artificial-lift system based on OPEX

A mature oil well provided an ideal opportunity to select a new artificial-lift solution by comparing operating

costs. The well, which had an initial production rate of 3,000 STB/D at 65% water cut, depleted over time to less

than 1,200 STB/D. The existing ESP was nearing the end of its operating life due to wear, was oversized for the

current well conditions, and was running at 30 Hz in a down-thrust condition (Figure 5). The well’s operator was

forced to replace the downhole lift system with a more efficient lift solution, ahead of imminent ESP failure.


Table 1 Well parameters at the onset of the evaluation process

Initial flow rate 3,000 STB/D at 65% water cut

Current flow rate 1,180 STB/D at 97.5% water cut

Oil API 18.2

Fluid mixture specific gravity (SG) 1

Production level 3,650 ft

Tubing head pressure 220 psi

Tubing length 4,520 ft

Tubing outside diameter (OD) 4 1/2 in.

Power cost $0.10 per kWh

Figure 5 ESP curve for the current operation (flow rate of 1,180 STB/D) at 30 Hz

Two options were considered and compared for their OPEX savings—a smaller-size ESP system and a long-stroke

pumping unit. The comparison began with an investigation of the estimated power requirements for an ESP.

Power estimation for ESP

Several theoretical assumptions were made to simplify the analysis:

• A single phase flow in tubing

• Formation volume factor = 1

• Specific gravities of the mixture fluid at surface and in-situ conditions are the same.


The Total Dynamic Head (TDH) requirements for an ESP this well are determined as follows:

THH is feet of head generated by tubing head pressure

FL is the production fluid level (TVD)

Hfr is feet of head lost due to friction in tubing

The feet of head developed by tubing pressure was estimated by using Equation 2:

THP is the tubing head pressure

SG is the specific gravity of the fluid mixture

Substituting in the provided values for THP and SG, THH is calculated as follows:

Friction losses in the tubing can be found using the Hazen-Williams formula:

Hfr_1000 represents friction losses in tubing per 1,000 ft of length

C is the pipe coefficient (120 for a new pipe)

Q is the flow rate (STB/D)

D is the tubing inside diameter (in.)

After plugging well parameter values into Equation 3:

The total friction losses in tubing are estimated as follows:

Hfr = 1.22 ft x 4.52 = 5.5 ft

H��_1000 = �.� � ��

�� .��

� � ��.� �

.��

� �.�� = 1.22 ft

H��_1000 = �.� � ��

� � .��

� � ��.��

.��

��.��

(3)

THH = �� .�

� = 508.2 ft

THH = � ! � �.�

"#

(2)

TDH = THH + FL + Hfr

(1)


By entering the above calculations into Equation 1, we can estimate TDH requirements for this well:

Let’s select an ESP capable of producing 1,180 STB/D while developing 4,164 ft of head.

An ESP with an OD of 5.13 in. and a recommended operating range of 750-1,792 STB/D at 50 Hz is suitable for a

production rate of 1,180 STB/D. One stage of this pump model develops 32.8 ft. Let’s estimate the number of

stages required to develop 4,164 ft of head.

Figure 6

A new ESP for 1,180 STB/D

From Figure 6, the required pump power is 68 horsepower (HP).

The following motor configuration is used for this application:

88 HP; 1,890 V; 34 A; 50 Hz

To define surface power, let’s estimate voltage drop in 4,600 ft of cable #4 American wire gauge (AWG), as seen

in Figure 7.

# Stages = 4,164 ft/32.8 ft = 127 (~130 stages)

TDH = 508.2 ft + 3,650 ft + 5.5 ft = 4,164 ft


Figure 7 Voltage drop in cable

Figure 7 shows that the voltage drop per each 1,000 ft of # 4 cable at 34 Amps is 16 V. Thus, the total voltage

drop in cable can be estimated as follows:

Surface power can subsequently be calculated as follows:

Assuming a power factor of 0.93, 89 KVA equals approximately 83 kW.

Let’s estimate power cost for 15 such wells with ESPs featuring a 3-year average run life.

$ Power = $0.1 x 83 kW × 15 × 24 × 365 × 3 = $3,271,860

(5)

$�,&�' (.)* � � � �.((� �.( �,�� = 89 KVA

KVA = $+,-.� ' +,-./01 23,�* � 45�� 6,/2 � �.(

�,��

(4)

Voltage drop = 16 V × 4.6 = 73.6 V


Power estimation for the long-stroke pumping unit

The HP requirements for the reciprocating rod lift are estimated as follows (Brown, Kermit, E, 1980, 2a, 43):

PRHP is the polished-rod HP

CLF is the cyclic load factor (equal to 1.054 for this application)

E is the surface system efficiency (equal to 75% for this application)

PRHP comprises hydraulic HP (HPh) and HP for friction losses (HPf). HPh is found as follows (Brown, Kermit, E,

1980, 2a, 43):

Q is the flow rate (STB/D)

THH is feet of head generated by tubing head pressure

FL is the production fluid level in feet (TVD)

From Equation 7:

Let's define the HP requirements for friction losses (Brown, Kermit, E, 1980, 2a, 44):

W is the weight of rods (lb)

S is the stroke length (in.)

N is the speed (SPM)

The following rod taper is used for this application:

Interval 1: rod diameter = 1 1/8 in.; rod weight = 3.676 lb/ft; rod length = 1552 ft

Interval 2: rod diameter = 1in.; rod weight = 2.904 lb/ft; rod length = 2,698 ft

Interval 3: sinker bar diameter = 2 in.; sinker bar weight =10.7 lb/ft; sinker bar length = 300 ft

Therefore, the total weight of the rod sting is estimated to be 16,750.14 lb

HPf = 6.31 x 107( × W × S × N

(8)

HPh = 7.36 × 107) × 1,180 STB/D × 1 × (508.2 ft + 3,650 ft) = 36.11 HP

HPh = 7.36 × 107) × Q × SG × (THH + FL)

(7)

HP = 8!9 !: � 8;6<:

=

(6)


To produce 1,180 STB/D, the long-stroke pumping unit—with a stroke length of 306 in. and equipped with a 3

1/4-in. downhole pump—is supposed to operate at a speed of 4.2 SPM.

After plugging all required data into Equation 8, the HP required for friction losses is estimated as follows:

Therefore, polished-rod HP is estimated as follows:

Finally, the surface HP can be estimated by plugging the values into Equation 6:

It is now possible to estimate power cost over three years for 15 such wells pumped by long-stroke systems.

This is 37.4% lower than the power cost of the ESP producing the same flow rate.

Comparison of OPEX for ESP and long-stroke unit

Even though both artificial-lift systems have similar sales prices, the overall OPEX associated with the ESP is

nearly $3,670,020 higher, as seen in Table 2.

$0.1 × 52 kW × 15 × 24 × 365 x 3 = $2,049,840

HP surface = 49.7 × 1.054/0.75 = 70 HP (~52 kW)

PRHP = 36.11 HP + 13.6 HP = 49.7 HP

HPf = 6.31 × 107( × 16,750.4 lb × 306 in. × 4.2 SPM = 13.6 HP


Table 2

OPEX comparison for the ESP and the long-stroke pumping unit

Long-Stroke RRP ESP

Total System Sales Price $300,000 $300,000

Downhole pump price $9,000 $145,000

Percent of total price 3% 48%

Total downhole price $59,000 $235,000

Percent of total price 20% 78%

Variable speed drive (VSD) $45,000 $65,000

Rig time (days) 1 1

Workover cost $12,950 $148,950

Failure rate (over 3 years) 1 1

Workover cost (over 3 years for 15 wells) $194,250 $2,234,250

Power cost (over 3 years for 15 wells) $2,049,840 $3,271,860

Downhole pump inventory (3 pumps for 15 wells) $27,000 $435,000

OPEX for 15 wells over 3 years $2,271,090 $5,941,110

Savings from using long-stroke system $3,670,020

Power cost reduction 37%

Workover cost reduction 91%

Inventory cost reduction 94%

OPEX reduction 62%

The reason for this significant OPEX difference is evident upon further examination of the price breakdown of

both systems in Table 2. The total downhole price comprises the price of the rod pump and sucker rods for the

long-stroke system, while for the ESP this price comprises the downhole pump (centrifugal pump, intake,

protector, and motor) and the downhole power cable.

As shown in Table 2, 78% of the ESP cost is concentrated downhole, while only 20% of the long-stroke system

cost is concentrated downhole. Since downhole equipment is exposed to a more severe operating environment

(high pressures and temperatures, corrosive fluids, solids) than the surface equipment (which has to contend

with atmospheric pressures and temperatures, wind, sun, and rain), one might infer that the operator puts 78%

of the investment at risk when using ESP for this application. At the same time, the operator puts only 20% of the

investment at risk when long-stroke pumping units are used.


This statement is further supported by field experience showing that long-stroke surface units have an average

run life of between 20 and 25 years and a high salvage value. As for downhole systems, whether it is an ESP or a

rod pump, the run life is significantly lower because these systems are constantly exposed to the harmful effects

of the wellbore environment.

Table 2 also shows that the workover cost for the ESP is 91% higher than for the long-stroke unit. Let's review

the calculations that have produced such results. In Table 2, the downhole pump price ($9,000) represents the

price of the reciprocating rod pump for the long-stroke system. For the ESP, this price ($145,000) represents the

price of the downhole pump, intake, protector, and motor. The total downhole price represents the total price of

the downhole rod pump and sucker rods for the long stroke system ($9,000 + $50,000 = $59,000). For the ESP,

this price ($235,000) includes the downhole system ($145,000) and the power cable ($90,000). The VSD price for

the ESP represents the price of a VSD, a step-up transformer, a lighting arrestor, and a load filter.

Workover costs include rig rental cost, cost of deferred production, and the replacement price of a downhole

pump. For the long-stroke system, this cost is calculated as follows: ($1,000/day × 1 day) + (1 day × 29.5 STB/D ×

$100/barrel of oil) + $9,000 = $12,950. For the ESP, workover cost is calculated as: ($1,000/day × 1 day × 29.5

STB/D × $100/barrel of oil) + $ 145,000 = $148,950.

OPEX is estimated as a sum of workover cost (assuming one failure per 3 years), power cost for 3 years, and the

cost of 3 downhole pumps used as inventory for an oilfield consisting of 15 such wells. For the ESP, for example,

this works out to $2,234,250 (workover cost over 3 years for 15 wells considering run life of 3 years per well) +

$3,271,860 (power cost of ESP wells for a life span of 3 years) + $435,000 ( 3 ESPs at $145,000 each).

Conclusions

This exercise has demonstrated that the long-stroke pumping unit may provide significant financial benefits for

operators in wells that were traditionally considered to be low- and medium-flow ESP applications.

The paper has analyzed a well that requires artificial lift to produce fluid at a rate of 1,180 STB/D. While both the

ESP and the long-stroke pumping unit can deliver such a production rate, the OPEX associated with the long-

stroke unit is lower, thanks to benefits in three major areas:

• Power cost reduction of 37%

• Workover cost reduction of 91%

• Inventory cost reduction of 94%

The combined result is an OPEX reduction of 62%.

References

Brown, Kermit, E. (1980). The Technology of Artificial Lift Methods (2a ed), p 43.

Pennwell Publishing Company.

Weatherford ESP application engineering manual (2011).

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