24 MAY 1999 •

f there is sufficient reservoir pressureto lift fluids to the surface, newlycompleted oil wells can be expected

to flow for years before increased waterproduction and/or decreased gas/liquidratios make it necessary to place the wellon some form of artificial lift in order tomaximize its ultimate potential for produc-tion and profitability.

Commonly used artificial-lift methodsfall into two groups: those that use pumpsand those that use gas. Pump-type methodsuse sucker-rod pumps, hydraulically oper-ated pumps, electrical submergible cen-trifugal pumps, and progressive-cavitypumps to lift fluids. Gas lifting methods useinjections of economically available gas tolighten the fluid column of a well and raisethe fluid by expansion of the gas.

Whatever means of artificial lift is cho-sen, the purpose is to maintain a reduced

producing bottomhole pressure so the for-mation fluids can flow into the wellboreand be delivered to the surface.1

When Nature FailsWhen the formation drive mechanism fails,a well must be converted to a method ofartificial lift that will enable it to continueto produce. However, considerable caremust be taken to select the most appropri-ate lift method.

In their book, The Technology ofArtificial Lift Methods, Kermit Brown,John Day, Joe Byrd, and Joe Mach make itclear that a thorough understanding ofthe flowing well is necessary to determinewhen and how it should be placed on arti-ficial lift.

“In its latter stages of flowing life, a wellis capable of producing only a portion ofthe desired fluids. During this stage . . . and

particularly after the well dies, a suitablemeans of artificial lift must be installed sothe required flowing bottomhole pressurecan be maintained,” the authors explain.“Maintaining the required flowing bottom-hole pressure is the basis for the design ofany artificial lift installation; if a predeter-mined drawdown in the pressure can bemaintained, the well will produce thedesired fluids. This is true regardless of thetype of lift installed.”

For more than a century, oilmen havebeen inventing, employing, and evolvingvarious methods of artificial lift. An exam-ination of all the different types of artificial-lift methods ever employed would encom-pass volumes. Therefore, this article willconcentrate on an examination of the his-tory, evolution, significant events, and peo-ple responsible for today’s most widely usedartificial-lift methods.

Subsurface Equipment/Artificial Lift:

Maximizing Production from the Well

S e r i e s S p o n s o r e d B y S P E F o u n d a t i o n

I

• MAY 1999 25

In the BeginningIn October, 1859, Colonel Edwin Drakerigged up a pump to produce an oil andwater mixture a distance of ten feet to thesurface.2 It was the world’s first commercialoil well and the first use of artificial lift tocommercially produce oil. Today, 140 yearslater, downhole pumps are still the mostpopular method of producing oil andoil/water or oil/gas/water mixtures. In fact,pumps are employed in more than 80% ofall artificial-lift wells; only the prime-movermechanism differs.3

Beam PumpingThe walking beam pump, the grandfatherof today’s counterbalanced oilfield pump-ing units, was an idea borrowed from thewater-well industry. One end of a heavywooden “walking beam” set on a pivot wasattached by a stiff rod to a steam engine.Attached to the other end of the beam wasa string of long, slender “sucker rods”,which were connected to a pump at thebottom of the well. The engine cranked therod up and down and actuated the pump topump oil to the surface.

This method was employed until shortlyafter the turn of the century, when opera-tors began demanding improvements inequipment and procedures. By the 1920’s,the demand for better methods led theindustry to focus on ways to improve thebeam pumper.4

It was W.C. Trout who answered the call.Trout ran a small foundry and machiningbusiness in Lufkin, Texas, which servedsoutheast Texas sawmill operators needingfoundry and equipment-repair services.Trout saw the production of oilfield pump-ing units as a way of expanding the compa-ny’s business. In 1925, in a field at Hull,Texas, Trout introduced his counterbal-anced pumping unit.5

Major improvements of the Trout pumpincluded the addition of a counterbalanceweight and a worm-gear system to reducethe size of the engine needed to power theunit. Since its introduction, the Trout-designed pump has become the dominantartificial-lift beam-pumping unit.

Over the years, the basic principles of abeam-pumping unit haven’t changed much.The rotary motion of a crank arm is con-verted into oscillating motion by means ofthe walking beam. The crank arm is con-nected to the walking beam by means of a

pitman arm, and the beam is supported bythe Sampson post and the saddle bearing.

The horse’s head and the bridle—or thehanger cable arrangement—are used toensure that the pull on the sucker-rodstring is vertical at all times so that nobending moment is applied to that part ofthe sucker-rod string above the stuffingbox. The polished-rod and stuffing-boxcombination is used to maintain a good liq-uid seal at the surface.6

Sucker RodsA sucker-rod string is the connecting linkbetween the surface pumping unit and thesubsurface pump located at, or near, thebottom of the oil well. The vertical motionof the surface pumping unit is transferredby the rods to the subsurface pump. Twotypes of rods are in use today—steel andfiberglass-reinforced plastic rods. About90% of those are steel rods.

“When sucker rods were first invented inthe mid-1860’s, they were made of wood,”says Dean Hermanson in The PetroleumEngineering Handbook. “The rods were fash-ioned from long wooden poles with metalends bolted to the wooden rod. One of thefirst improvements involved the develop-ment of an all-metal rod. By 1880, the newiron sucker rods had replaced the woodenones. Over the ensuing decades, the geom-etry of the rods remained relativelyunchanged, but additional improvementswere made in the surface finish, condition,end straightness, metallurgy and qualitycontrol to achieve increased performanceand corrosion-resistance.”

The first fiberglass sucker rods appearedin the 1970’s. They consisted of long paral-lel strands of fiberglass embedded in a plas-tic matrix. Steel fittings are mounted on theends of the rods. Standard couplings jointhe rods together so the sucker-rod stringcan be made up.

Fiberglass rods offer two distinct advan-tages over steel rods—lighter weight and alower modulus of elasticity. They are espe-cially popular for wells with relatively highfluid levels where excessive rod stretch candestroy the efficiency of the installation.

Another important improvement to thestandard sucker rod also occurred in thel970’s. It was the development of the con-tinuous sucker rod. The idea wasn’t new. Itis believed that braided-wire cable used inearly wells (circa 1860) to operate down-

hole pumps represents the first use of acontinuous sucker rod. The modern ver-sion of a continuous sucker rod is essen-tially a continuous length of steel used inthe same way as conventional sucker rodsto actuate either reciprocating rod pumpsor rotary progressing-cavity pumps.7 Byeliminating the rod couplings, the continu-ous sucker rod assists in optimizing wellproduction and is ideal for horizontal ordeviated wells where couplings wouldinterfere with rod operation and fatiguecould shorten the rod’s lifespan.

Sucker-Rod-Performance PredictionAlthough seemingly simple, in field prac-tice predicting the behavior of a beam-pump and sucker-rod system is surprising-ly complex. In fact, this prediction is socomplex it has received the attention ofengineers and mathematicians for morethan 60 years.

During the mid-1950’s, a group of majoroil companies and equipment manufactur-ers (now the American Petroleum Inst.)was organized to investigate the complexbehavior of a conventional pumping unitdriving an elastic rod string. As a part oftheir effort, they began using electrical ana-log computers to simulate the sucker-rodsystem. By solving the wave equation as itapplied to certain rod-pumping assump-tions, the computer generated syntheticsurface and bottomhole pump dynamome-ter cards. Data from these syntheticdynamometer cards were used to generatenondimensional design curves, which werethen employed to develop predictive meth-ods for sizing pumping units.8

In the late 1960’s, S.G. Gibbs, a graduatestudent and math major, noted that Britishphysicians were using computer models tomaximize the analysis of electrocardio-grams (EKG’s). The computer would usemathematical equations to fully analyze thecharacteristic “squiggles” that are plottedby the EKG machine. Until this time, doc-tors had to interpret the EKG plot subjec-tively to determine the condition of thepatient’s heart.

Gibbs theorized that the same techniquemight be valuable in diagnosing the perfor-mance problems of artificial-lift equipment(submergible pumps, sucker rods, meteringdevices). “I wanted to take the subjectivityout of problem solving,” says Gibbs. “I rea-soned that if we could cast the sucker-rod

26 MAY 1999 •

wave equation into a general mathematicalmodel of sucker-rod behavior similar to theway the British doctors did on the EKGplot, we could eliminate the costly trial anderror methods (methodically pulling wellequipment and checking each piece) beingused at that time. By devising a reliable wayof pinpointing a performance problem, wecould confidently get a pulling unit and goout and fix the problem on the first try.”

What resulted was Gibbs’ sucker-roddiagnostic technique. “The technique usesmathematical equations to model the elasticbehavior of long sucker rod strings,” saysGibbs. “A computer takes the data and useswave equations to model the performanceof the well’s artificial lift equipment anddetermine a solution for the well’s problem.”

By solving the wave equation as itapplied to sucker-rod pumping, Gibbs wasable to simulate accurately and mathemat-ically beam and sucker-rod pumping per-formance with any type of unit geometryoperating under any given set of pumpingconditions. It was a powerful achievementthat is employed today routinely through-out the world.

However, when Gibbs debuted his tech-nique, it wasn’t exactly greeted with openarms. “When we introduced the tech-nique 40 years ago, we were greeted withskepticism by field operations people,”says Gibbs. “They were skeptical that thetechnique could solve their performanceproblems. In fact, they tended to stay withtheir old trial and error methods. But,eventually, they came to believe in it, somuch so that today, many company crewswon’t pull a well without an analysisusing the technique.”

Gas LiftGas lift is another important artificial-liftmethod. This method artificially lifts fluidsby the continuous or intermittent injectionof relatively-high-pressure gas into a well’sflow tube. In the gas-lift process, the inject-ed gas aerates the fluid to be lifted, causingit to become lighter. This, in turn, enablesthe formation pressure to force the liquid upthe wellbore to the surface. Gas lift is espe-cially suitable for offshore wells becauseplatform space is limited and the gas-liftequipment is largely located downhole.

Since its development in the 1930’s, thepercentage of wells going on gas lift hasincreased continually because it can be usedin applications where beam pumping isn’tappropriate or practical. Also, gas-lift equip-ment requires a minimum of maintenance.

Kermit Brown, a former U. of Tulsa andU. of Texas professor of petroleum engi-neering and an industry-acknowledgedauthority on gas-lift technology, cites thedevelopment of two subsurface-equipment

devices as having a profound influence onmodern gas-lift technology.

“I think the invention of the bellows-typegas lift valve was probably the most impor-tant piece of equipment ever invented forthe gas lift industry,” says Brown.

“The other important development wasthe wireline retrievable side pocket mandrelwhich allowed operators to pull gas valvesfor repair without pulling the tubing.”

The King Bellows Gas-Lift ValveThe invention of the single-element, unbal-anced, bellows-charged gas-lift valve in1940 by W.R. King revolutionized gas-liftapplication and installation design meth-ods. Before King invented his bellows valve,numerous types of unique devices wereused for gas lifting wells. These devices, orvalves, were operated by rotating or verti-cally moving the tubing and by means of asinker bar on a wireline.9

The gas valve is the heart of most gas-liftinstallations, and King’s valve gave theseinstallations the predictable performanceessential for successful gas-lift design andoperations. Additionally, the King valveprovided the flexibility to allow for a chang-ing depth in the point of gas injection tocompensate for a varying flowing bottom-hole pressure, water cut, daily productionrate allowable, and well deliverability.

The Side-Pocket MandrelEarly gas-lift valves were the conventionaltype in which the tubing mandrel thatholds the gas-lift and reverse check valveswas part of the tubing string. It was neces-sary to pull the tubing to replace a faultygas-lift valve.

“The first selectively retrievable gas liftvalve and mandrel was developed around1951 by Harold McGowen and H.H. “Red”Moore in conjunction with the Perry R.Bass Foundation,” Kermit Brown explains.“The retrievable valve mandrel wasdesigned with a pocket, or receiver, withinthe mandrel. A gas lift valve could beremoved or installed by simple wirelineoperations without pulling tubing. Themandrel is called a sidepocket mandrelbecause the pocket is offset from the cen-terline of the tubing.”

“This wireline retrievable system for gaslift valves revolutionized the application ofgas lift for inaccessible wells,” says Brown.“It eliminated the need for a rig to round-trip the tubing and has saved operators a lotof time and money.” Newer mandrels haveorienting devices to ensure successful wire-line operations in highly deviated wells.

Electrical Submergible Pumps (ESP’s)According to Clarence Dunbar, a retiredengineer who spent most of his career

designing, developing, and marketing ESP’sfor artificial-lift applications, the first elec-trical submergible pumping unit was devel-oped in Russia in 1917 by ArmiasArutunoff. Unfortunately, that was thesame year the Bolshevik Revolution beganand Arutunoff was forced to flee toGermany to continue work on his pump.Bad luck continued to hamper Arutunoff.It wasn’t too long before life in Germanybecame overly difficult, so in 1921Arutunoff migrated to California to contin-ue efforts to commercialize his pump. Atsome point during the early 1920’s,Arutunoff installed the first ESP in an oilwell. However, California’s high-volume oilwells tended to be very sandy and theirabrasiveness was troublesome forArutunoff’s pump.

In 1928, Frank Phillips of PhillipsPetroleum Co. in Bartlesville, Oklahoma,became interested in the Arutunoff pumpand decided to provide financial resourcesto further develop the pump for use infields where Phillips operated. WithPhillips’ backing, expanded use of ESP’s inthe oil industry was assured. Since thattime, the concept has proved to be an effec-tive and economical means of lifting largevolumes of fluid from great depths under avariety of well conditions.

It should be noted that Arutunoff wasvery adamant that his pump be called a sub-mergible pump rather than a submersiblepump. He reasoned that while numerouspumps were submersible in liquids, theycould not be operated without being dam-aged while submerged. After years of argu-ing his point, Arutunoff successfully con-vinced the publishers of Webster’sDictionary to make the distinction.

Today’s ESP’s are essentially multistagecentrifugal pumps that employ blades, orimpellers, attached to a long shaft. Theshaft is connected to an electrical motorthat is submerged in the well. The pumpusually is installed in the tubing justbelow the fluid level, and electricity issupplied through a special heavy-dutyarmored cable.

ESP’s have seen a great deal of evolu-tionary development during the past 70years, much of which occurred duringthe 1950’s.

“The development of higher temperatureinsulation for pump motors and the cablesthat supply electricity made a big differ-ence,” Dunbar explains. “In the early days,bottomhole temperatures ranged from 125to 150°F. As the wells were drilled deeper,the temperatures got higher. Now, thanks tobetter insulation material, electric pumpingis used routinely in wells with BHT’s inexcess of 300°F and depths of more than12,000 ft.

28 MAY 1999 •

“Another critical outgrowth was thedevelopment of high nickel cast iron for usein making pump impellers and diffusers,”Dunbar continues. “Originally, these com-ponents were made of bronze, but thenickel cast iron is harder and more abra-sion-resistant which makes the pumpswork better in sandy wells.”

Additionally, the decade of the 1950’s sawthe development of a mechanical seal foruse in the pump’s protector/seal section.“Prior to the development of the seal, com-mon lead packing seals were used,” saysDunbar. “They really didn’t provide muchconsistency in keeping water out of thepump motor. Sometimes they gave a longrun, other times a short run. Pump life-spans weren’t very predictable.

“The mechanical seal allowed a balancedpressure between the inside and outside ofthe pump motor,” Dunbar states. “The use ofa baffle system prevented high pressure fromoccurring across the seal face, thereby effec-tively keeping water out of the motor andvastly improving its operational lifespan.”

Dunbar remembers that another bigmilestone in ESP evolution was develop-ment of computer programs for the selec-tion of ESP’s for high-gas/oil-ratio wellsduring the 1970’s. “The programs made itmuch easier to select the type of pump andto calculate the number of stages requiredfor a specific well application,” Dunbarstates enthusiastically. “It really cut the timerequired for the calculations that previous-ly were done by hand.”

Subsurface Hydraulic PumpsHydraulic pumping made its appearance asa method of artificial lift in oil wells duringthe early 1930’s. Since that time, the methodhas found wide acceptance, especially indeep, high-volume pumping applications.

There are two types of hydraulic pumpsfor artificial lift. One is fixed-pump design,the other is free-pump design. In fixedinstallations, the downhole pump isattached to the end of the tubing string andrun into the well. Power fluid is directeddown an inner tubing string and the pro-duced fluid and the return power fluid flowto the surface inside the annulus betweenthe two tubing strings.

Free-pump installations allow the down-hole pump to be circulated into and out ofthe well inside the power-fluid tubingstring, or they can be installed and retrievedby wireline operations. Of the two types ofhydraulic-pump installations, the freepump offers the most significant advan-tages. These installations permit circulatingthe pump to bottom, producing the well,and then circulating the pump back to thesurface for repair or size change. The bene-fits of being able to circulate the downhole

pump in and out of the well includereduced downtime and the ability to oper-ate without a pulling unit for tubing, cable,or rod removal.

Jet pumps are a special class of hydraulicsubsurface pumps and are sometimes usedin place of reciprocating pumps. Unlikereciprocating pumps, jet pumps have nomoving parts and achieve their pumpingaction by means of momentum transferbetween the power fluid and producedfluid. Also, they are popular because theyare compact and can be adapted to fit inter-changeably in bottomhole assembliesdesigned for stroking pumps.

“Although references to jet pumps can befound as early as 1852 and 1864, it was notuntil 1930 that W. F. McMahon received thefirst six patents on the oilwell jet pump,”says Howard Bradley in The PetroleumEngineering Handbook. “Subsequently,McMahon built and marketed the pumps inCalifornia in the late 1930’s. While theyfound use locally, they never achievedwidespread acceptance. However, in 1970,hardware improvements and the advent ofcomputer models for correct applicationsizing in oil wells led to the successful mar-keting of jet pumps. Their popularity hasgrown since.”

The FutureTwentieth Century evolutionary accom-plishments in subsurface and artificial-liftequipment have been numerous, but thequest for newer and better methods contin-ues. Oilmen seeking to maximize recoverywill demand more cost-effective artificial-lift choices in the future. The focus ofdevelopment in the 21st Century will like-ly include better artificial-lift technologiesfor deviated and multilateral completionsand continued improvements in existinglift technology.

Some of the most promising artificial-lifttechnologies of the future will involve intel-ligent-well completions (smart wells).These completions offer a combination ofsystems and processes that significantlyimprove producers’ ability to manage thereservoir. Downhole sensors and flow-con-trol devices operating in real time viaumbilicals from the surface improve therecovery of hydrocarbons without the needfor costly well intervention or workover.Smart-well systems determine flow rates,water cut, gas/oil ratio, and fluid composi-tion from each zone of a multiple-zonewell. In short, artificial-lift methods can beoptimized since producers can reconfigurea well’s architecture at will.

The deployment of the adjustable gas-liftvalve for smart wells is one of the cutting-edge technologies that will enable the opti-mization of artificial-lift methods during

the next decade. The valve, which isdeployed on a tubing string in a modifiedside-pocket mandrel, is significant becauseits injection flow characteristics areadjustable from the surface. Data fromdownhole sensors, which are received bythe surface reservoir-management systemin real time via umbilicals, enable operatorsto make flow adjustments that optimize thewell’s gas-lift-system operation. This, inturn, makes the system more efficient as itis produced. Before this valve’s introduc-tion, operators wishing to make valveadjustments were required to change thevalve by means of wireline intervention.

When the progressive-cavity pump (PCP)was introduced in the 1970’s, it was relegat-ed initially to production of high-viscosity,sand-laden heavy oil. During the 1990’s, itspopularity for use in artificial lift has grownsubstantially. And, that growth is expectedto continue well into the next centurybecause PCP’s offer a wider range of volumeand lifting capacities—they can operate atdepths up to 6,000 ft and have a maximumproduction rate of 4,000 bbl/day. Also, morepump choices exist to suit a broader range ofproducing environments, and new pumpmaterials have been developed for moreaggressive producing applications. Theseadvancements will allow wide acceptancefor employment in shallow, high-water-cut,high-volume production and de-watering ofcoalbed-methane wells.10

References11. Brown, K., Day, J., Byrd, J., and Mach, J.: The

Technology of Artificial Lift Methods, Vol. 2a,

Petroleum Publishing Co., Tulsa (1980) 2.

12. Knowles, R.S.: The First Pictorial History of

the American Oil and Gas Industry 1859-1983,

Ohio U. Press, Athens, Ohio (1983) 7.

13. Day, J. and Byrd, J.: “Beam Pumping: Design

and Analysis,” The Technology of Artificial Lift

Methods, Vol. 2a, Petroleum Publishing Co.,

Tulsa (1980) 9.

14. Fundamentals of Petroleum, third edition,

Petroleum Extension Service, U. of Texas,

Austin (1986) 179.

15. Lufkin Industries Inc., http://www.lufkin.

com/corp/history/pump.htm

16. Day, J. and Byrd, J.: “Beam Pumping: Design

and Analysis,” The Technology of Artificial Lift

Methods, Vol. 2a, Petroleum Publishing Co.,

Tulsa (1980) 9.

17. EVI Oil Tools Inc., http://ww.evioiltools.

com/rodlift3.html

18. Brown, K., Day, J., Byrd, J., and Mach, J.: The

Technology of Artificial Lift Methods, Vol. 2a,

Petroleum Publishing Co., Tulsa (1980) 80.

19. Bradley, H.B.: Petroleum Engineering

Handbook, third printing, Society of

Petroleum Engineers, Dallas (1992) 5–12.

10. “Artificial Lift,” Weatherford “W,” Weatherford

International Inc. (winter 1999) 23.