performance evaluations of the different sucker rod artificial lift...

SPE-189231-MS

Performance Evaluations of the Different Sucker Rod Artificial Lift Systems

M. Kennedy Dave and M. Ghareeb Mustafa, SSI Lift

Copyright 2017, Society of Petroleum Engineers

This paper was prepared for presentation at the SPE Symposium: Production Enhancement and Cost Optimisation held in Kuala Lumpur, Malaysia, 7-8 November 2017.

This paper was selected for presentation by an SPE program committee following review of information contained in an abstract submitted by the author(s). Contentsof 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 reflectany position of the Society of Petroleum Engineers, its officers, or members. Electronic reproduction, distribution, or storage of any part of this paper without the writtenconsent 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 maynot be copied. The abstract must contain conspicuous acknowledgment of SPE copyright.

AbstractThe majority of oil wells operated throughout the world requires some form of artificial lift during their lifecycle. Wells lifted by reciprocating sucker rod pumping systems represent almost more than 70 % of thetotal artificially lifted oil wells worldwide.

As consequence of previous and current global crisis, the pressure on the operators is to maximizingproduction and net profit out in a very safe and environmentally controlled manner. The primary challengeis to select the suitable system capable to achieve these goals over the life cycle of the well. For years,operators have been looking for reliable, flexible and intelligent lifting systems to improve their operatingcosts, reservoir recovery factor by maximizing well production and filed safety.

There are several sucker rod-pumping systems applied all over the world. Each has its differentadvantages and disadvantage. Selecting the right system technology requires detailed analysis, includingwell, fluids, reservoir and location.

This study will present detailed comparisons between the different systems in the area of production,depth, downhole failures, power saving, safety related to system operations. The comparison will be betweenthe conventional beam, enhanced geometry beam, linear vertical mechanical Long Stroke pumping unitsand long stroke Wellhead Mounted Hydraulic pumping units systems. This study was undertaken usingadvanced predictive methods. The results compared with actual field applications from Canada, USA, LatinAmerica and Middle East. The latest technology in sucker rod pumping systems regarding the system’scapabilities as production, depth, optimization, power consumption and control considered in this study.

IntroductionArtificial lift is need in wells when there is insufficient energy (depleted and/or naturally flowing wells)in the reservoir to lift the desired production rate of the well fluids to the surface with wellhead pressurecapable to displace the produced fluid to the production facilities.

Generally, this is achieve by the use of a device inside the wellbore and/or by decreasing the weight ofthe hydrostatic fluid column by injecting gas into the liquid some distance down the wellbore.

There are several types of artificial Lift systems using to move the production fluids to the surface.

○ Reciprocating Sucker Rod Pumping (SRP)

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○ Electric Submersible Pumps (ESP)○ Progressive Cavity Pumps (PCP)○ Gas Lift (GL)○ Plunger Lift (PL)○ Hydraulic jet pumps (JP)

The earliest documented reciprocating walking beam artificial lift system described in the Egyptianhistorical writing dated 476 AD2 and called Shadof as shown in Figure 1. It was limited to lift low volumeof water from shallow depth.

Figure 1—First beam unit system (Shadof)

With the time, the new discover oil reservoirs (oil fields) became harder in production as fluid type,production rate, reservoir pressures, well depth, hole characterizations …etc. This push the manufacturesto present and develop different forms of surface and subsurface equipment in order to produce thesereservoirs.

The mechanism introduced to oil industries was not different in principle than Shadof. It is name BeamPumping units (pump jacks or surface pumping units). Different geometries and configurations introducedas shown by Figures (2a) and (2b). The beam unit is used to stroke the bottom hole pump up and down. Thisis accomplished by converting rotary motion to reciprocating vertical motion. Rotary power is supplied toa gear reduce by a prime mover. The gear reducer uses a series of gears to convert the high-speed powersupplied by the prime mover to low speed power. (Usually a ratio of approximately 30 to 1 on a doublereduction unit). The gear reducer turns the cranks and the cranks lift the pitman arms up and down (rotaryto reciprocating). The pitman arms move the walking beam up and down consequently the horses head onthe opposite end of the walking beam has to go up and down. This action causes the bridle cable to movethe carrier bar up and down which in turn moves the sucker rod string up and down and consequently thetraveling valve that connect to plunger.

SPE-189231-MS 3

Figure 2a—Conventional Beam Pumping Units

Figure 2b—Enhanced Geometry Beam Pumping Units

These traditional beam pumps has not seen much evolution or change in over 100 years. These type ofpumping units are limited in the capabilities to produce high fluid volume and improve the well performancein difficult wells (wellbore and/or fluids). Some of these challenges are:

• The mechanical wear between rod and tubing especially in deviated and/or crooked holes whichpresent a friction problem

• Inefficient pumping in gassy wells

• Depth limited, primarily because of rods and surface unit capabilities.

• Obtrusive in urban locations.

• Safety hazards. Pumping units have large and heavy rotating parts.

To overcome some of these challenges the manufactured introduced in the late 1980s a mechanical long-stroke pumping unit (Figure 3). It offered many advantages over traditional beam pumping units. Thisvertical mechanical system is lacking of the flexibility of changing stroke lengths where it is limited to threeof four choices.

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Figure 3—mechanical long-stroke pumping unit

Today’s due to the level of the oil prices, well operators require more control on well operation andeconomics than the beams and mechanical long stroke units can do. To address this, industry has introducedintelligent hydraulic skid mounted long stroke pumping units Figure 4. They offer fully flexible longerstroke lengths which allowing operators to make the same or more fluid with less number of strokes. Thisresult in less wear and tear on the sucker rods, tubing and the bottom-hole pump. Reduced wear will reducedthe frequent well interventions, and increase mean time between failures (MTBF). This will lead to increasewell production and reducing lifting cost and safety hazard. In addition, this new type of hydraulics unitsare able to overcome the rod fall (carrier bar separation) issues.

Figure 4—Long Stroke Hydraulic skid mounted unit

Systems Evaluation for Well Depth and Production CapabilitiesMany factors must be consider when evaluate the performance of the applied lift system for a particularwell. One of the main evaluation criteria is the range of depth and production rate where particular lift typescan function.

The ability of a sucker rod pumping system to produce a fluid is constrained by (1) the stroke length,(2) the plunger diameter of the bottom-hole pump, (3) the strength of the sucker rods, (4) unit capacity and

SPE-189231-MS 5

geometry and (5) the rod free fall from a given well. For any given pumping unit the critical pump speedis controlled by two main variables, (1) stroke length, and (2) the well forces, such as friction, buoyancy,etc., that retard rod fall (Byrd, 1968).

Several field studies and simulations done to predict the behavior of the rod lift system to produce apracticality high volumes production. The majority of these studies ignored rod buckling tendency andalmost most of them when studied the system capabilities as production and depth not considered the effectof wells and fluids problems. It will be cover in this study.

A simulation study made by using one of program using for sucker rod pumping system design (SROD)to compare the performance of four of common using long stroke surface pumping units (conventionalbeam enhanced geometry beam, mechanical long stroke and hydraulic skid mounted long). This study doneby consider three different cases for well depths and productions. Table 1 presented the criteria used in thedesigns.

Table 1—Criteria used in the design.

Depth 5000 8000 11000

Production 1000 700 300

Pump intake Pressure psi 100

Surface wellhead Pressure psi 200

Tubing Size inch, 3.5

Water Cut % 50

Oil Gravity API 30

Water Gravity 1.05

A number of general assumptions were applied in making these simulations. In all cases the wellsconsidered vertical and tubing was anchored, thus no tubing stretch. The output results of the simulation forthe three cases are shown in Tables 2, 3 and 4 for three depths 5000 ft, 8000 ft and 11,000 ft respectively.Analyses of the three tables indicates that as stroke length increases, the required pumping speed SPM(stroke per minutes) to produce the same volume of fluid decreased. This lead to decrease PPRL (peakpolished rod load) while MPRL (minimum polished rod load) increases due to dynamic effects. Thiswill increase the well performance and reduces well intervention due to decreasing buckling tendencies,decreasing side & drag loads, decreasing rod loading and decreasing the load range (PPRL – MPRL). Fewercycles mean less rods, tubing, and pump wear will be seen Lower losses of stroke as a percentage of thetotal stroke, making the system more efficient.

Table 2—simulation results for well producing 1000 BFPD form 5000 ft.

C 1280 D-365-192 M 912 D-365-192 RF 1150 - 500 - 366 SSI 350-372

Power Required (hp) 73.47 72.61 54.82 55.87

Surface Max Load (lbs) 29454 29680 27422 27308

Surface Min Load (lbs) 4826 2668 7627 7801

Average Pumping Speed (SPM) 7.65 7.73 3.41 3.4

Polished Rod Horse Power (hp) 44.85 45.78 42.41 43.22

Computed Surface Stroke (in) 193.3 192.3 366.1 372

In-balance Max Torque (m in-lbs) 1204.3 966.9 161.6 NA

Pump Diameter (in) 2.75

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C 1280 D-365-192 M 912 D-365-192 RF 1150 - 500 - 366 SSI 350-372

Net Pump Stroke, inches 147.6 146.7 332.7 339.3

Net bpd at 100% pump eff 1000

Rod Loading % 76 80 65 64

Service Factor 0.9

Rod Type UHS

Rod String 86


C 1280 D-365-192 M 912 D-365-192 RF 1150 - 500 - 366 SSI 350-0372







In-balance Max Torque (m in-lbs) 1313 1116.1 183.9


Net Pump Stroke, inches 139.6 135.9 327.8 329.4



Service Factor 0.9

Rod Type UHS

Rod String 86


C 1280 D-365-192 M 912 D-365-192 RF 1150 - 500 - 366 SSI 350-0372







In-balance Max Torque (m in-lbs) 1010.9 789.4 147.3


Net Pump Stroke, inches 157.4 154 334.8 340.3



Service Factor 0.9

Rod Type UHS

Rod String 86

SPE-189231-MS 7

Systems Evaluation by Operation Modes and Related Downhole FailuresSucker rod operation modes are usually designed based on well production and well & fluids conditions.Three main parameters are mainly controlled well production rate and well performance. These parametersare subsurface pump, stroke length and pumping speed. The stroke length and pumping speed are generatedby the surface pumping unit. Therefore selecting the right surface pumping unit can have great impact inthe system performance and controlling the equipment failures frequency. For a particular production rateand set of well conditions there are many combinations of stroke lengths, strokes per minute and plungerdiameter.

Most failures associated with the reciprocating sucker rod pumped wells can be attributed to oneof downhole components (subsurface pump, sucker rod string, tubing string…etc.). Failure of thesecomponents will required servicing rig to pull and change out one or more of these parts. The rate ofthe failure frequency (Numbers of component failures/ well, per year) will have direct impact in the wellperformance and economics. Effectively manage the failures rate to generate the highest revenue possiblewill required carefully select the most efficient running parameters in order to reduce well failure frequencyrate.

Using the simulation data presented by tables 2, 3 and 4, the type of the surface unit and its operationalmodes are cleared in its effect in the equipment running lives and system performance for the followingcommon problems:

• Rod buckling: It is one of the main problem in rod-pumped wells especially deviated well. Ithappens during the downstroke. The rod buckles and contact against tubing. It cause tubing wareand leaks. It can also cause rod parts. The main reasons for rod buckling are:

◦ Downhole friction, especially in a deviated well due to larger drag friction.

◦ Pumping speed. Increasing pumping speed especially in the downstroke can cause rodcompression due to the rod dynamic. Tension force becomes a compression at free end ofpump. It happens both in vertical and deviated wells. Pump-off condition and /or under-balancecondition may also aggravate buckling. Some unit geometry may also aggravate bucklingtendency at fluid pound condition.

◦ Most cases of rod buckling happens at any combination of above.

Comparing the performance of Beam, Hydraulic Skid mounted long stroke and mechanical longstroke units along with their features and controller capabilities in running wells with rod bucklingproblems, indicated that the longer the stroke the better the performance in handling this type ofwells. This is mainly due to several reasons. The longer stroke especially ultra-long stroke lengthunits allow to use a smaller subsurface pump size to handle the same production. Use smaller pumpwill reduce the fluid loads consequently reduce the side/drag loads between rods and tubing. Longstroke with smaller pump size and slow speed will reduce the dynamic caused rod buckling andpeak polished rod load. The buckling tendency overcome to high degree when using hydraulic unitswith the integrated intelligent control system. Adjustable accelerations and decelerations at the topand the bottom of the stroke combined with variable speed control on the up and down stroke.

• Fluid Pound: As experienced in a pumping oil well, fluid pound is one of the most commonoperational problems. It is caused when the subsurface pump not completely filled with liquid onthe upstroke. As the downstroke begins, the entire fluid and rod string load moves down through avoid until the plunger hits the fluid level in the pump barrel which transmits a shock wave throughthe pumping system (Figure 5). This shock wave causes damages entire parts of the pumpingsystem. This problem occurs when the downhole pump operated at a rate exceeds the productionrate of the formation. It is usually the main cause of fatigue failures of the surface pumping unit

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(structure, gear teeth, bearings and unit base), rod string. It accelerate subsurface pump components(valves, valve rod and barrel) failures. Also fluid pound accelerates wear of the tubing due to rodbuckling.

Performance evaluation of the different surface pumping units in running wells suffered frompounding fluids done based on the units concept of operation and its flexibility in adapting theunit’s running parameters (speeds and stroke length). Followings are the main observations:

• Conventional and enhanced geometry beam units which have fixed speed for up and downstrokes,the performance were found to be very low and the reported failure rates were very high. Initiallythe operators improve the situation by used well timers and pump off controllers. The use of timersor pump off controllers lead in some wells to reduce the well production. This is because in theperiod of down time, the well production will decrease with increasing the fluid level (well willbe under build-up condition). Also, since it is primarily used as an on/off type control, the systemwill transfer from static to dynamic several time per hours. This will accelerate the motor, surfaceunit, rods failures. The situations was notices worst in the cases when using the enhanced geometryunits. This is because this units featured with faster downstroke speed compared with the upstroke.The fasted down stroke increase the shock wave what the plunger hit the fluid inside the pumpbarrel. Also, on and off is not preferred for well produce with certain amount of sand. San can fallback on top of the plunger if the off periods.

• Linear vertical mechanical Long Stroke pumping units’. This unit proved to be much better thanBeam type units. Manly due to the feature of the long stroke and slow pumping speed. This allowfor more time for (Fill Time) the fluid to inflow to the pump during the upstroke. When unit isequipment with variable frequency drive, pumping speed can be slow down. The drawdown of suchtype of unit is the availability of the stroke lengths. It is limited to 3 to 4 lengths. This will reducethe chance to reduce the unit running parameters in order to match well productivity. Thereforechance of fluid pound problems is exist.

• Hydraulic skid mounted Long Stroke Pumping Units. This type of units shows the best performancein running wells with fluid pounding problem. This is mainly found to be due to the differentfeatures these units have. Where with very simple adjustments while the unit is running, an operatorcan optimize the system to match pumping conditions to well productivity. The stroke length can bemade from one inch to the maximum allowable stroke with one inch increments. For example, a unitequipped with 360 inches, the available stroke lengths are 1, 2, 3, 4………….358, 359,360 inches.This wide range of stroke lengths with the availability to speed up or down the units, operator canadjust very closely the unit running parameters to match well productivity and fluid pound canalmost eliminated.

It also featured with independent Up and down stroke speed. Speed can be control by slowingdown the up stroke period in order to allow for more time for (Fill Time) the fluid to inflowto the pump during the upstroke. The longer the time interval of the upstroke, the longer thefill time to charge the barrel, and the greater the amount of fluid permitted to inflow during theproductive cycle; hence, increased production. Moreover to avoid the shock force resulting fromfluid pounding condition, this type of system is featured with a very smart automation system whichcan lead to almost eliminate the bad effect of the fluid pound in the entire system. It provides EightIndependent Speeds for Up and Down Stroke plus Independent Acceleration and deceleration forUp and Down Stroke. The unit can be adjusted to slow down almost near to zero speed in thedownstroke before it hits the fluid level inside the pump. This will allow the plunger to pass thefluid without any shock load and by that, the fluid pound will eliminated.

SPE-189231-MS 9

Figure 5—Fluid Pound

Safety related to system operationsSucker rod pumped well are running with large equipment running 24/7. Therefore when we compare thedifferent surface unit’s safety hazards, we need to consider all the type of operations where the times ofparticular danger can happen. This can occur mainly during:

• The erection,

• Stroke change,

• Counterbalance change,

• General unit maintenance,

• Well servicing and

• While taking dynamometer card reading.

A review of recent and historic incidents show that Beam type units related worker fatalities is the worstamong the other type of units. This is because Pumping units have large and heavy rotating parts. Even atemporarily stationary pumping units has components which can start moving from the effect of gravity.Comparing with the long stroke vertical units where almost all moving parts enclosed within the tower andaway from personnel, very few incidents reported. The Hydraulic skid mounted computerized units recordedthe safest units. Where No crane required for work-over activities a tracking system for sliding pumping unitback and forward for well workover without dismantle the unit is using. Therefore less injuries exposureobserved. Also all the required operations for changing stroke length, pumping speed and balancing theunits found to be more safer where all can be done without stopping or access the units. All these operationsdone from the power skid.

Case HistoriesCase Study 1: San Ardo, California oil producer had a need to increase production beyond that whichwas possible with a beam pump, but wanted to avoid the additional costs of operating an ESP, while alsoreducing maintenance costs resulting from frequent rod separations.

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To achieve the goal the producer installed late in 2008 four Skid mounted long stroke pumping unitswith 100 hp power units. Immediately upon startup, the long stroke units have resulted in a more than 25%increase in production over the beam pump's production of less than 2,000 BFPD to over 2500 BFPD oneach well. This production increase has been achieved while decreasing strokes per minute by 60%, from 10SPM to 4 SPM. This has resulted in substantially lower failures frequency for downhole parts (rod, tubingand downhole pump.

Installation & Purchase Payback in 6 Weeks; Over $1 Million Increase in Annual Cash Flow per Welldue to the this increased in production and reducing in well interventions costs

Case Study 2: Major International Producer Wyoming, USA have wells had severe side loading andhigh frequent well services. Being June 2013 they installed four ultra-long stroke hydraulic SSI units. Thisin order to evaluate the performance of using the fully control long stroke hydraulic units with the target ofreducing rod cycles (failures) while l maximizing liquid production. No tubing or rod failures up to date.

Case Study 3:A Wasson Clearfork Team evaluated the performance of Hydraulic ling stroke skid mounted units on

deviated wells. The results was concluded as follows:Increased Production - In one case, a Conventional 912 pumping at 7.9 SPM with a 2.25" BHP

producing 420 BFPD was changed to DynaPump Model 9 pumping at 4.3 SPM with a 2.25" BHP and endingup producing 505 BFPD. This was a 20% increase without changing the size of the BHP. In most cases,the BHP was increased to the next larger API pump size and production increased at least proportionally,although in a few cases the well was subsequently pumped off with the larger pump. In at least one case,the change to the DynaPump (SSI Lift)resulted in an increase in the production of oil by 25 BPD.

Less Down Time and Rig Cost – Certain wells have relatively high well maintenance cost related torod parts, tubing wear out, and BHP failures. Operator has even experienced some wells using submersiblepumps that have a high rate of replacement. Of course any time a well must be pulled to complete repairsthere are two negative operating factors that come into play: one is the cost of the rig crew plus the cost ofthe replacement parts, and the other factor is the lost production revenue while the pump is out of service.One common characteristic of the wells that have very high well maintenance costs is that they have asevere deviation profile. In these cases, beam pumps running very fast experience a high rate of partedrods even when steps are taken to use rod guides in the deviated section(s). Submersible pumps sometimesexperience electrical harness damage when being inserted on deviated wells which then leads to prematurepump failure. Use of a DynaPump (SSI Lift)on such wells allows production to be maintained, or in mostcases increased as noted above, but with the pump stroking at approximately ½ the speed of a normal beampump.

Conclusions and Recommendation

• When rod buckling, rod on tubing wear, rod parts and fluid pound are a problem, then a longer andslower stroke per minute with a smaller plunger size will decrease the failures frequency, improvethe performance and increase run life consequently reduces Well Intervention by:

◦ Lowering peak polish rod load

◦ Reducing the loading by creating higher minimum polish rod load

◦ Decreasing buckling tendencies

◦ Decreasing side loads and drag loads

• The effects of rod string compression are expensive and unnecessary, and it can be greatly reducedwhen long stroke units are utilized.

SPE-189231-MS 11

• Adjustable upstroke and downstroke speeds allow for more pump fillage.

• Long-stroke sucker-rod pumping units have definite advantages as compared to conventional beamunits. They produce greater liquid rates with less downhole pump problems and can also increasethe life of the rod string due to the reduced number of stress reversals

• Ultra-long stroke configuration provides efficient pumping in deep, troublesome, and high-volumewells

• For high safety and less hazard related to well operation for persons and equipment, the SkidMounted units are proved to be the best choice. Where all well operation can be done from thepower skid

AcknowledgementsThe authors wishes to express their thanks to Tundra Process Solutions and SSi Lift Company for permissionto publish this paper. Especially thanks for all SSi Team for their constructive advice and support.

NomenclatureAPI Rodstring 86

Tapered rod string stared with 1" rod at the top , 7/8" rod at the middle and ¾" rod at thebottom

BPD Barrel per dayBFPD Barrel fluid per day

BS&W Basic sediment and waterBWPD Barrel water per day

ESP Electrical submersible pumpft Feet

GOR Gas oil ratioHMI Human Machine Interface

HP Horse powerIbs Poundsin Inch

MMSTBO Million stock tank barrel oilMPRL Minimum polished rod loadOPEX Operating Expenses

PLC Programmable Logic ControllerPPRL Peak polished rod load

PSI pound per square inchVFD Variable frequency drive

SAGD steam-assisted gravity drainageSR Sucker rod

STB Stock tank barrelUHS Ultra high strength

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