Joe Dunn Clegg is a senior staff production engineer for ShellWestern E&P Inc. in Houston. He has worked since 1952 withartificial-lift design, installation, operation, evaluation, andtraining, and has had assignments in west Texas, the RockyMountain region, and Louisiana. He is currently involved withartificial lift, completions, well surveillance, productionengineering computer programs, standards, and guidelines.Clegg was a 1984-85 Distinguished Lecturer and a member ofthe 1985-87 Annual Meeting Well Completions TechnicalCommittee, serving as chairman during 1986-87.

sPEDistinguishedAuthor SERIES

High-Rate Artificial LiftJoe Dunn Clegg, * SPE, Shell Oil Co.

Summary. This paper summarizes the major considerations in the selection, design, installation, operation, or repair of high-rateartificial-lift systems. The major types of artificiallift-sucker-rod pumps, gas-lift systems, electrical submersible pumps, hydraulicpumps and jets, and hydraulic turbine-driven pumps-will be discussed. An extensive bibliography of artificial-lift papers isincluded.

IntroductionThe need for better design and more efficient operation ofhigh-rate artificial lift continues to be one of the moreimportant artificial-lift problems. Many of the older fields thatare now flowing will require high-rate artificial lift. Also,waterflooding and water injection for pressure maintenancehave increased the need for higher lift rates.

SelectionSelection of the type of artificial lift is very important. In sucha selection, the three major economic factors are income,operating cost, and capital cost, generally in that order. Thetype of artificial-lift system chosen should produce the reservesin a timely fashion with minimum operating costs. An efficientsystem may well be worth some additional capital costs.Making a bad selection will have adverse effects on the netincome and may result in a change to a different type ofartificial lift.

One of the initial steps in any design selection is to setpriorities. Such things as location, lift depth, and casing sizehave a large influence on the type and size of equipment.Important issues in an offshore field can be significantlydifferent from a dry-land location. The importance of cashflow, total present value profit, and reserves must be weighed.

High.Rate Rod PumpingRod pumping is not normally considered to be particularlyapplicable for high-rate artificial-lift systems. However, use ofrelatively long stroke units, large plungers, and high pumpingspeeds should be reviewed if for no other reason t~an toestablish a norm.

A good general rule is to install rod pumping if the desiredproduction can be obtained without encountering severe orunusual lift problems. Possibilities range from lifting 4,000BFPD from 1,500 ft [635 m3 /d fluid from 460 m] to 1,000BFPD from 4,000 ft [160 m 3/d fluid from 1220 m].

The problems of lifting high rates from shallow wells arequite different from lifting from deep wells. In high-rate,

'Now with Shell Western E&P Inc.Copyright 1988 Society of Petroleum Engineers

Journal of Petroleum Technology, March 1988

shallow wells, the major problems are normally rod fall andhigh peak torques, not rod stress. The API design method (APIRP llL) appears to be inaccurate for design of shallow wellswhere the conditions of low nondimensional pump speed(NINo) and low nondimensional fluid loads (FoISkr) exist. Indesign of high-rate, shallow rod systems, we must rely onother design approaches (i.e., use of the wave-equationprograms or field experience). In general, for high-rate,shallow lift, relatively large pumps should be installed and theunits run as fast as the rods will fall without excessivelyoverloading the equipment. Larger pump sizes running atrelatively slower speeds are theoretically more efficient thansmaller pumps running at higher speeds.

Deep, high-rate rod-pumped wells are limited primarily bythe high rod loads. The API design method usually gives"ballpark" load answers and predicts reasonably well thechange in loads for different operating conditions. To deal withhigh rod loads, the users are forced to go with higher-strengthrods, such as the API Type D or special high-strength rods.High cyclic loads and rod abuse will cause repeated rodfailures, which in turn will result in extremely high operatingcosts and excessive downtime. Efforts to improve rod life arealmost always worthwhile. Good surveillance is essential inrod-pumped fields when lifting high rates. Also, it is veryimportant to provide effective corrosion inhibition as soon aswater becomes the wetting phase.

Pumping-unit care and maintenance also deserve to havehigh priority because the units are the most expensive piece ofequipment in the rod-pumping system. Both the gearbox loadsand the structure load must be considered. The API designassumes that the unit is in perfect balance, which seldomoccurs in practice. As water cuts and lift depths increase, thereis a tendency to overload the gearbox. Loads exceeding thegearbox rating may significantly shorten life.

Keeping the structure of the unit from being overloaded isalso important. Beam bending or failure of the base seldomoccurs. Occasionally, a base weld may crack but can be easilyrepaired. The primary problem with overloading is bearingfailures. Doubling the load results in reducing the bearing life

277

200 to 750400 to 1,500500 to 2,500750 to 4,000

1,000 to 6,0002,000 to 7,500

>5,000

NormalProduction Range

(B(D)1.9952.4412.9923.4763.9584.7366.366

Tubular SizeID

(in.)

TABLE 1-PRODUCTION RATES FORDIFFERENT TUBING SIZES'

Rod Grade & Tlper

~C ..

E8 0 ..

!!!!! ...3.000

2.500

2.000

1.500

3.500

'.500 ,------------------------,

DEPTH (1000 FEET)

Fig. 1-Maximum rod pump rate for C912D·365·168 unit.'Based on an 8,000-11 well. a GOR of 2,000 113/bbl, and a50% water cut.

2,500

Fig. 2-Typical tubing performance fot three tUbing sizes.

by a factor of eight. A bearing failure often results in tearingup the unit structure. If the unit is overloaded, steps should betaken immediately to reduce loads or to replace the unit with alarger one. Use of fiberglass rods in the deeper wells willoften reduce unit loads and may permit an increase in rate.

The largest conventional beam-pumping unit currentlymanufactured is a C-912D-365-168. Fig. 1 is a bar graph thatgives the maximum allowed pump rates for various lift depthsfrom 1,000 to 10,000 ft [300 to 3000 m]. In making such agraph, one must consider speed, rod load, structure rating,geatbox size, and sucker-rod type and design. An examinationof this graph shows the rapid falloff in rate as depth increases.Higher-strength rods may be required as depth increases.

Lufkin Mark n™ and Baker Torqmaster™ units alsodeserve consideration and have been used successfully by manyoperators. Such units have improved geometry overconventional units. These special units normally operate withreduced peak torques.

The biggest beam units available are the air-balanced design(one manufacturer lists an A-2560D-470-240 unit). These unitsare expensive and somewhat more complicated than aconventional unit. Thus, most operators prefer to useconventional units. Air-balanced units make good well testunits because they are more compact and do not have theheavy counterbalance weights. They are also better suited forjacket or platform installation. One additional advantage is thatthese units are easier to balance because courrterbalance can beadjusted by a simple change in the air pressure.

Gas LiftContinuous-flow gas lift is an excellent high-rate artificial-liftsystem for many fields. Like all lift systems, it has advantagesand limitations. One essential requirement is sufficient lift gasfor the life of the project.

The size of the tubing is very important in gas lift,especially when trying to lift high rates. To pick the right sizeof tubing, the designer needs a good two-phase vertical-flowcorrelation. Many correlations are suitable, but no correlationis perfect for all conditions. The accuracy should always bechecked with good data obtained under similar conditions.Appropriate PVT data and corrections for deviated wells arenecessary.

Tubing-performance curves can be developed for the well orfield of interest through a good two-phase-flow computerprogram (see Fig. 2). Such curves demonstrate the importanceof the tubing size. All these curves have the same generalshape. For low rates, the required flowing bottomhole pressureis relatively high. As rates increase, the pressure decreasesuntil it reaches a minimum. Thereafter, the pressure increasesmore and more as rates increase. This increase is caused byfriction loss in the tubing. The high pressures at low rates area result of slippage. The tubing size should be chosen tocorrespond to a rate that is greater than the minimum pressurevalue but does not have excessive friction loss. Picking toosmall a tubing will result in high friction losses, whereaspicking too big a tubing will cause severe heading in gas lift.A range of rates normally suitable for each tubing size isshown in Table 1.

Gas-lift design and valve placement is a good-news/bad-newsproblem. The good news is that a working design can be madewith few or no data. The bad news is that good data arerequired to make an efficient design that will produce the wellnear its maximum potential. High-productivity-index wells arevery sensitive to the injection depth and should have closevalve spacing in the vicinity of the calculated injection point.

For high-volume lift, e.g., more than 2,000 BID [320m3 /d], the use of ll/z-in. [3.8-cm] -OD valves has beenreported to be beneficial. These valves permit use of a largergas injection port, which allows a higher gas injection rate. Inthe typical Gulf of Mexico well, which normally produces farless than 2,000 BID [320 m3 /d], the use of I-in. [2.5-cm]valves with ~kin. [OA8-cm] ports is usually adequate. Manyfields have had good experience with I-in. [2.5-cm] valves.

Besides the beam units, several different types of long-strokerod units are available. Most of these are designed to give along, slow stroke, which may theoretically be a betteroperating condition for the sucker rods. These large specialtyunits, however, have often proved expensive and have beenoperated with less reliability than conventional units. Also, therod life in many cases was apparently not improved.

•.....................

--~

4,000 5,000

DEPTH: 8,000'

CUT: 50%

GOR: 2,000

3,000

../ .. /

.....................

.....

2.0001,000

FLOW RATE (8PO)

500 '--__-.JL- -.J .

o

PWF

2.000

~<IIeoO'II::><II<IIO'II:

1.5000-O'

~:E0I:0III

1,000

278 Journal of Petroleum Technology, March 1988

One key to obtaining good valve operation is to ensure thatthe valves are aged properly and set correctly (without muchdrift in pressure). Simple injection-pressure-operated valves arenormally used to unload to the point of injection. A carefullyselected orifice for the operating "valve" (injection point) hasbeen used successfully by Shell and others.

The gas injection pressure is often selected on the basis ofgas sales pressure rather than on a pressure that will producethe well most efficiently. The gas injection pressure needs tobe selected to result in the lowest compression horsepower perbarrel of fluid lifted when injecting near-optimum gas volumes.This usually means that the injection pressure must be highenough to lift from near bottom, just above the packer fortubing flow. By injecting near bottom, one can either lift morefluid (a higher drawdown) Or use less injection gas to lift agiven volume. In many cases, increased fluid production anddecreased injection gas have resulted from deeper injection.

A high-rate gas-lift well equipped with 3.958-in.[1O.053-cm] -ID tubing is shown in Fig. 3, where threeinjection pressures (800, 1,400, and 1,800 psig [5520, 9650,and 12410 kPa]) are plotted. Also plotted is the well'sequilibrium curve, which shows the lift depth and tubingpressure to produce various rates. For this well, the 800-psig[5520-kPa] system will produce about 3,250 BID from 3,000 ft[515 m3/d from 915 m]; the 1,400-psig system, about 5,000BID from 6,200 ft [795 m3/d from 1890 m]; and the1,8oo-psig system, about 5,600 BID from 9,000 ft [890 m3/dfrom 2740 m]. In this case,the higher injection pressure willproduce at a higher rate, will require less gas per barrel offluid lifted, and should be more profitable.

High weI1head backpressure is a serious problem in manyhigh-rate wells, especially those on gas lift. Production can beincreased and lift horsepower decreased by reducingbackpressure on the well. Long or small-ID flowlines, highseparator pressures, or chokes result in restricting production.These problems need to be identified and corrected.

Because compressed gas is costly, designing the system toproduce at the absolute maximum rate with a minimumgradient is rarely, if ever, the most profitable approach. Inmost U.S. fields, the optimum injection volume is significantlyless than the volume needed to achieve a minimum gradient.One rule of thumb is that the total injection gas should notexceed half the rate to achieve the minimum gradient. Anothergeneral approach is to design for an operating condition thathas a producing pressure 50 to 100 psi [345 to 690 kPa] abovethe minimum pressure at the point of injection. Doing an in­depth design study requires the analysis of capital cost,operating cost, and income over the life of the project.

For a limited system that is already installed, the availableinjection gas should normally be distributed so that themaximum possible oil production is obtained. Some wells mayneed to be restricted, and others may need to be produced

0800 psi system yoo.1 \00 ~; .,.t~psi system

.'02000

2.0002500",.

\3000"~...

3500--., ,aUIL'.R'UM \4.000

CURVE --'000 ...{ \

.500' 1\6.000 "

5OOO"',~

\;~... \8.000

I \

Ito.ooo0 . 8 " 16 20 " 28 32

PRESSURE IN 100 PSIA

Fig. 3-Gas-lift example for various system pressures.

even though the gas could, for the short term, be better usedelsewhere. The total injected gas per barrel of produced oil issometimes used for the best injection-gas allocation scheme.Each well will have a unique curve of oil produced per 1,000ft3 [28 m3] of injection gas. When the incremental rate of oilproduction per 1,000 ft3 [28 m3] of injection gas is equal forall wells, then the highest income should result. Often in high­volume lift, this results in giving the better oil wells the mostgas and the high-water-cut wells the least gas. If reserves arenot lost, then such an allocation method is recommended.

Electrical Submersible PumpsElectrical submersible pumps (ESP's) have been recognized foryears as a high-rate artificial-lift system, and in the past fewyears, use has increased. If the well conditions are right, thenas much as 80,000 BFPD [12700 m3/d fluid] can beproduced. The initial capital is often attractive, lower thanother equivalent artificial-lift systems.

An ESP system requires a rather precise rate design, goodtraining of both engineers and operators, careful equipmentselection, good manufacturers, quality control, correctinstallation, a reliable electrical system, stable operatingconditions, excellent repair and maintenance procedures, andcareful selection of the type of well for installation. ESP's,like all pumps, are adversely affected by sand, scale, orfree gas.

The physical size (OD) of the motor is important in mosthigh-volume installations. Larger motor diameters for a givenhorsepower have lower capital costs and are more energyefficient, more rugged, and less expensive to repair. Thus,your high-volume wells should be equipped with large casingand a relatively large motor. In general, the lift rate is limited

12,000 .------.-------.------.--------.----,y/!L-

'::!~\~"'....w....."'._1-- t- t-:_:_=_:_o_F;U_e~d_at_ia_n-+ -1

::: j;; ..:;;\:. \:::::::11'6 5/8 Casing (Large Shaft Pump)

o 10,000 20,000 30,000 40,000 'Y 80,000

PRODUCTION RATE (BBLS/DAY)

Fig. 4-Maximum producing rate of ESP for various casing sizes.

Journal of Petroleum Technology, March 1988 279

PROD\;lCTlON RATE (THOUSANDS OF BBlS/DAY)

Hydraulic PumpingHydraulic pumping has been used for more than 50 years forartificial lift; however, its use has always been limited and itsshare of the market small. Hydraulic lift is used for high-rateartificial lift often on a default basis where other lift methodswould have serious problems. Hydraulic pumping has someunique advantages but also some severe limitations.

Hydraulic pumping has the ability to pump relatively highrates from great depth, and the capital costs are oftencompetitive with rod pumping (see Fig. 6). Hydraulic pumpingis not sensitive to temperature. Also, if a free pump is used,tubular pulling should be infrequent. Corrosion control byinhibition is easily done, and the displacement can be easilychanged. Deviated holes present few problems, and wells canbe operated with either central control or individual controlsystems.

Hydraulic pumping has a difficult time competing with ESPin high-volume wells where temperatures and lift depths arenot excessive. In many offshore locations, hydraulic pumpingis not competitive with gas lift where GLR's are high, sandproduction is common, and gas venting up the casing is notdesirable. Short pump runs and high operating costs arefrequently encountered in hydraulic pump systems. Produced­oil-volume-measurement accuracy is particularly difficult inhigh-water-cut wells when oil from a central system is used asthe power fluid.

High hydraulic pumping cost can often be reduced by properdesign. Surface pumps for the power fluid are usually triplexor quintuplex piston pumps rated at 5,000 psi [34.5 MPa].Operating costs can be kept much lower if pressures are keptbelow 3,500 psi [24.1 MPa] when water is pumped and below4,000 psi [25.6 MPa] when oil is pumped. (Some engineersrecommend values that are 500 psi [3.4 MPa] less.) Themaximum pump speeds recommended by the manufacturers arehigh, possibly by as much as 25 %. Keeping the pump speeddown should increase pump life. High friction pressure lossescan be avoided if the lines and tubing are sized properly.Small casing often prevents using the size of tubing needed,thus resulting in more friction losses and possibly causingdifficulty in gas venting. If gas is to be vented, two tubingstrings are normally required, which complicates thecompletions.

The use of SCR's for soft start and for time-cycling the wellis relatively new. Most operators have had poor experiencewith conventional ESP oilwell installations that were frequentlyshut down and started. The problem was mostly electrical,with failures primarily in the cable. Startup amperage spikesfive to seven times the normal running current are common,and voltage spikes also occur on shutdown. These spikes arebelieved to cause failure in any weak spots in the electricalsystem. By use of SCR's, a soft start occurs, resulting incurrent peaks of only two to three times the running currents,and voltage spikes on shutdown are negligible. These SCR'sare used only during shutdown and startup so that normalsystem efficiencies are not reduced as with the VSD's. Successin time-cycling wells equipped with SCR's has been reported.

Major problems have also occurred with ESP systems inhigh-temperature (>200°F [>93°CD oil wells. Suchconditions may exist in deep wells. Conversely, most operatorshave had few temperature-related problems in producingshallow water wells. The high-temperature problem is relatedmostly to the cables. Some cables are rated to 350°F [177°C],but most operators seriously doubt that long cable life (greaterthan 5 years) can be obtained at such high temperatures. Evenat 200°F [93°C], special cables and handling are required toobtain a reasonable cable life.

Most operators have found that considerable effort isrequired with ESP operations to obtain reasonable repair andmaintenance costs. If such costs can be kept under control,ESP is an excellent high-rate artificial-lift method. Trainingand operating procedures are extremely important in ESPoperation.

DEPTH (1000 FEET)

Fig. 6-0isplacement vs. depth for some representative hy­draulic pumps.

o4

cill 3.000

!zw:;;w(,)

~3; 2,000i5

1.000

+---\---I\------'<-+-'<----+----+---~--~~___c

4,000

5.000

Fig. 5-Maximum producing rate of ESP in 5.5-in. -00 casing.

0+----\---+---+-----+-----+-------1o

FOR 1.0 SG FLUID AND 60 HZ OPERATION

+--\--f-\:---*---'.....-+-------+------ -~-----~-

by the size of the electric motor that can be run (see Figs. 4and 5). Tandem motors can be used, but this may increaseoperating costs significantly.

Good well data are required to select a pump size thatoperates in the recommended range. If the pump capacity ishigher than the well inflow, the well will pump off and theunderload current will normally shut the system down. Whenoversized, the pump operates in a downthrust region, whichtends to shorten its life. On the other hand, an undersizedpump will not reach the desired production.

During the past few years, two developments have aidedpump-capacity sizing: variable-speed drives (VSD's) and softstart using silicon-controlled rectifiers (SCR's). These twodevelopments certainly make ESP operation more versatile.VSD's are expensive and result in some loss of efficiency(which can be high if not adjusted properly). The ACfrequency (hertz) can be changed, which directly affects speedand thus capacity. As the hertz is changed, the head varieswith the speed squared, and the horsepower varies with thespeed cubed. One must take care not to increase the speed sothat the motor is overloaded or to decrease the speed so thatthere is not ample head. Despite these shortcomings, theVSD's have given the operator more flexibility in operatingESP's in fields where rates are uncertain or where theychange. The VSD's also permit a soft start, which can reduceESP failures.

280 Journal of Petroleum Technology, March 1988

The short runs for hydraulic positive-displacement pumps areoften caused by poor fluid quality. Experience has shown thatthese pumps require less than 10 ppm undissolved solids forgood operation. Settling tanks or centrifugal desanders can beused to clean the power fluid but must be designed andinstalled properly. Salt deposition can reduce pump life but canusually be controlled by injecting a small volume of freshwater into the power-oil systems. Using water as the powerfluid creates other problems.

The jet production unit developed in the mid-1970's hasimproved and broadened the use of hydraulic-pumpinginstallations. These units have no moving parts; they use anozzle/throat/diffuser arrangement to convert a velocity head toa pressure head. Unit life is excellent and power fluid does nothave to be ultraclean. Use of jet units in lieu of hydraulicpumps has frequently reduced pump repair costs and simplifiedoperations. Also, jet units are a high-volume artificial-liftmethod suitable for many well conditions.

Jet units, however, are not very efficient and will requiremore energy input. Total system efficiencies on the order of20% or less can easily occur. Jets cannot be used effectively atlow suction pressures because of cavitation problems. Theywill handle only a moderate amount of free gas without afurther loss in efficiency. Jet units cannot compete with rodpumps on low-volume wells unless there is some specialproblem; however, jet pumping may compete with gas lift insome high-rate artificial-lift situations.

Hydraulic Turbine-Driven PumpsThe hydraulic turbine-driven downhole pump is a relativelynew high-rate artificial-lift system with some potential specialapplications. The downhole drive is a high-speed, multistagehydraulic turbine supplied by a high-pressure surfaceproduction unit. The downhole turbine drives a downholemultistage centrifugal-type pump. Hydraulic turbine-drivenpumps have several advantages: high-rate lift capabilities,operational flexibility, the ability to withstand hightemperatures (up to 392°F [200°C]), suitability for deviatedwells, high resistance to erosion and corrosion, and relativeease of transportation and installation.

The Weir hydraulic turbine-driven downhole pump is a high­quality product that has a relatively high capital cost. Thedesign intent was to produce a long-life downhole assemblythat would require infrequent pulling. In general, the turbineoperational speed lies in the range of 6,000 to 12,000 rev/min.An inherent advantage of the turbine-driven downhole pump isthat the speed of the downhole unit may be raised or loweredby a simple variation in the surface pressure/rate of the powerfluid. For efficient system operation, it is necessary that flow­friction losses are low in the supply and return tubulars. Likeany pump, free gas will reduce efficiency. Thus, for all gassywells, the gas needs to be vented up the annulus, whichrequires an additional tubing string.

ConclusionsI. A careful selection of the type of artificial lift is essential;

income, operating cost, and capital costs should be considered.2. Rod pumping is a high-rate method for relatively shallow

wells. Deeper, high-rate lift will result in high rod loads,which require careful attention.

3. Gas lift requires the careful selection of the tubing sizeand operating pressure in the initial design. Deep lift using the"optimum" gas rate is essential for efficient high-rateoperation.

4. ESP's require relatively large casing for high-ratepumping. VSD's and SCR's have improved flexibility;however, good design, quality control, and operating practicesare essential.

5. Hydraulic pumping has application for special high-ratedeep lift. Jet pumping has improved the operating life butgenerally has relatively low overall operating efficiencies.

6. Hydraulic turbine-driven downhole pumps have potentialin high-rate and high-cost applications.

Joumal of Petroleum Technology, March 1988

Nomenclaturefo = differential fluid load on full plunge area, Ibm [kg]k r = elastic constant-total rod string, Ibm/in. [kg/cm]N = pumping speed, strokes/min

No = natural frequency of straight rod string, strokes/minS = surface stroke, in. [cm]

AcknowledgmentMy appreciation goes to Shell Oil Co. for permission topublish this paper.

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Simmons, W.E.: "Optimizing Continuous Flow Gas Lift Wells," Pet. Eng.(Aug. 1972) 46-48; (Sept. 1972) 68-72.

Winkler, H.W. and Smith, S.S.: Cameo Gas Lift Manual, Camco Inc., Hous­ton (1962).

Electrical Submersible Pumps.Allis, D.H. and Capps, W.M.: "Submersible Pumping-Long Beach Unit

of East Wilmington Field: A 17-Year Review," lPT (Aug. 1984)1321-25.

Coltharp, E.D.: "Submersible ,Electrical Centrifugal Pumps," lPT (April1984) 645-52.

Coltharp, E.D.: "Subsurface Electrical Pump Well Test Analysis," paperSPE 3548 presented at the 1971 SPE Annual Meeting, New Orleans,Oct. 3-6.

Divine, D.L.: "Variable Speed Submersible Pumps Find Wider Applica­tion," Oil & GasJ. (June 11,1979) 111-19.

Hoestenbach, R.D.: "Large-Volume, High-Horsepower Submersible Pump­ing Problems in Water Source Wells," lPT (Oct. 1982) 2397-2402.

Kelley, R.S.: "Productivity Determination and Pump Resizing UsingVariable-Speed Electric Submersible Pumps," lPT(Sept. 1980) 1503-08.

Lea, J.F. and Bearden, J.L.: "Effect of Gaseous Fluids on SubmersiblePump Performance," lPT (Dec. 1982) 2922-30.

Lea, J.F. and Bearden, J.L.: "Gas Separator Performance for Submersi­ble Pump Operation," lPT (June 1982) 1327-33.

Lea, J.F. and Powers, B.: "Electrical Submersible Pump Teardown In­spection," Pet. Eng. (April through Sept. 1984).

Neely, A.B. and Patterson, M.M.: "Soft Start of Submersible Pumped OilWells," lPT (April 1984) 653-56.

282

Nolen, K. and Gibbs, S.: "Design of Submersible Electric Pumping Sys­tems," Proc., Annual Meeting of the Southwestern Petroleum ShortCourse, Lubbock, TX (April 1983) 344-60.

O'Toole, W.P. and O'Brien, J.B.: "Testing New Submersible Pumps forProper Sizing and Reduced Costs," paper SPE 15425 presented at the1986 SPE Annual Technical Conference and Exhibition, New Orleans,Oct. 5-8.

Steward, R.E.: "The Effects of Power Supply Integrity on Electrical Sub­mersible Pumping Systems," Proc., Annual Meeting of the SouthwesternPetroleum Short Course, Lubbock, TX (April 1980) 351-66.

Watson, A.J.: "ESP-The Electrical Submersible Pump," Pet. Eng. Inti.(May through Nov. 1983).

Hydraulic Pumping.Alford, B.J.: "Fire Protection for Hydraulic Pumping Installations," lPT

(Sept. 1968) 945-50.Coberly, C.J.: "Theory and Application of Hydraulic Oil Well Pumps,"

Kobe Inc., Huntington Park, CA (1961).Hollis, R.G.: "Deep Hydraulic Pumping-Reno Field," lPT(Nov. 1966)

1395-99.Kelley, H.L.: "Current Status of the Hydraulic Pumping System," paper

presented at the 1981 Kansas Oil Lifting Short Course, Great Bend, KS,March 11-12.

Nolen, K.B. and Gibbs, S.G.: "Subsurface Hydraulic Pumping Diagnos­tic Technique," paper SPE 4540 presented at the 1973 SPE Annual Meet­ing, Las Vegas, Sept. 30-0ct. 3.

Petrie, H. and Smart, E.E.: "The Theory, Hardware, and Application ofthe Current Generation of Oil Well Jet Pumps," Proc., Annual Meetingof the Southwestern Petroleum Short Course, Lubbock, TX (April 1983)251-82.

Wilson, P.M.: "Introduction to Hydraulic Pumping," Kobe Inc., HuntingtonPark, CA (1976).

Hydraulic Turbine Pumping.Riddet, D.A.: "Artificial Lift by Hydraulic Turbine-Driven Downhole

Pumps," paper SPE 13741 presented at the 1985 SPE Middle East OilTechnical Conference and Exhibition, Bahrain, March 11-14.

Ryall, M.L. and Grant, A.A.: "Development of a New High-ReliabilityDownhole Pumping System for Large Horsepowers," lPT (Sept. 1983)1709-18.

Miscellaneous.API Standards: 11AX, 11B, 11D, 11E, and 11D.API Recommended Practices: RP 11AR, RP I1BR, RP 11G, RP 11L, RP

liS, and RP 7C-11F.API Bulletins: Bull. llL2, Bull. 11L3, Bull. 11L4.

SI Metric Conversion Factorsbbl x 1.589 873 E-Ol m3

cycles/sec x 1.0* E+OO Hzft x 3.048 E-Ol m

ft3 x 2.831 685 E-02 m3

in. x 2.54* E+OO empsi x 6.894757 E+OO kPa

*Conversion factor is exact. JPT

This paper is SPE 17638. DistingUished Author Series articles are general. descriptivepresentations that summarize the state of the art in an area of technology by describingrecent developments for readers who are not specialists in the topics discussed. Wriltenby individuals recognized as experts in the area, these articles provide key references tomore definitive work and present specific details only to illustrate the technology. Purpose:To inform the general readership of recent advances in various areas of petroleum en­gineering. A softbound anthology, SPE DistinguishedAuthorSeries, Dec. 1981-Dec. 1983,is available from SPE's Book Order Dept.

Journal of Petroleum Technology, March 1988