selección de levantamiento artificial(fileminimizer)

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Copyright 1999, Society of Petroleum Engineers, Inc.

This paper was prepared for presentation at the 1999 SPE Mid-Continent OperationsSymposium held in Oklahoma City, Oklahoma, March 28-31, 1999.

This paper was selected for presentation by an SPE Program Committee following review ofinformation contained in an abstract submitted by the author(s). Contents of the paper, aspresented, have not been reviewed by the Society of Petroleum Engineers and are subject tocorrection by the author(s). The material, as presented, does not necessarily reflect anyposition of the Society of Petroleum Engineers, its officers, or members. Papers presented atSPE meetings are subject to publication review by Editorial Committees of the Society ofPetroleum Engineers. Electronic reproduction, distribution, or storage of any part of this paperfor commercial purposes without the written consent of the Society of Petroleum Engineers isprohibited. Permission to reproduce in print is restricted to an abstract of not more than 300

words; illustrations may not be copied. The abstract must contain conspicuousacknowledgment of where and by whom the paper was presented. Write Librarian, SPE, P.O.Box 833836, Richardson, TX 75083-3836, U.S.A., fax 01-972-952-9435.

Abst ractSelection of the most economical artificial lift method is

necessary for the operator to realize the maximum potentialfrom developing any oil or gas field. Historically the methodsused to select the method of lift for a particular field havevaried broadly across the industry, including

Determining what methods will lift at the desired ratesand from the required depths.

Evaluating lists of advantages and disadvantages. Use of expert systems to both eliminate and select

systems.

Evaluation of initial costs, operating costs, productioncapabilities, etc. using economics as a tool of selection.

This paper will highlight some of the methods commonly

used for selection and also include some examples of costsand profits over time calculated to the present time as a tool ofselection. The operator should consider all of these methodswhen selecting a method of artificial lift, especially for a

large, long-term project.

IntroductionIn artificial lift design the engineer is faced with matchingfacility constraints, artificial lift capabilities and the well

productivity so that an efficient lift installation results. Energyefficiency will partially determine the cost of operation, butthis is only one of many factors to be considered.

In the typical artificial lift problem, the type of lift has

already been determined and the engineer has the problem ofapplying that system to the particular well. The more basicquestion, however, is how to determine what is the propertype of artificial lift to apply in a given field.

Each of the four major types of artificial lift will be

discussed before examining some of the selection techniquesSome additional methods of lift will also be discussedPreliminary comments related to reservoir and well factors

that should be taken into consideration are presented.There are certain environmental and geographica

considerations that may be overriding issues. For examplesucker rod pumping is by far the most widely used artificial

lift method in the United States. However, if we are in the

middle of a densely populated city or on an offshore platformwith forty wells contained in a very small deck area, suckerrod pumping may be eliminated. Deep wells producing severalthousands of barrels per day cannot be lifted by beam lift and

other methods must be considered. These geographic andenvironmental considerations may simply make our decisionfor us; however, there are many considerations that need to betaken into account when these conditions are no

predetermining factors.

Reservoir Pressure and Well Productivity. Among the mos

important factors to consider are reservoir pressure and welproductivity. If producing rate vs. producing bottom-hole

pressure is plotted, one of two inflow performancerelationships (IPR) will usually occur. Above bubble pointpressure, it will be a straight line. Below bubble poin

pressure, a curve as described by Vogel will occur. These twocurve types are shown in Figure 1 as a single IPR with abubble point at about 750 psi.

Some types of artificial lift are able to reduce the

producing sand face pressure to a lower level than others. Thereward for achieving a lower producing pressure will dependon the reservoir IPR. For example, the well of Figure 1 wouldhave an absolute open flow (AOF) of about 670 bopd if nogas was being produced. However due to the gas, the AOF is

reduced to about 580 bopd. If you are using a pumping system

on this well, there may be good reason for not lowering thesand face pressure below about 500 psi as the increasingamount of free gas may cause gas interference and

diminishing returns on production with lowered pressure. Ialso would be difficult to lower the pressure as muchcompared to some other lift methods using gas lift although agassy well would in general be beneficial for gas liftapplications.

In addition to the older conventional IPR expressions forvertical wells, there are now available a number of IPR

SPE 52157

Selection of Artificial LiftJames F. Lea and Henry V. Nickens--Amoco EPTG/RPM


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2 J.F. LEA, H.V. NICKENS SPE 52157

models for horizontal wells. An input panel for one suchmodel is shown Figure 2. This allows calculation of inflowfrom a horizontal well, which typically produces severalmultiples of what a vertical well would produce in the same

formation.Use of horizontal well inflow models for present or for

future depleted horizontal wells can be used to determine if

the flowing production rates can be economically increasedthrough the use of some method of artificial lift. If thehorizontal well is low pressure and ceases to flow, the inflowmodel can estimate what the well could produce if suppliedwith a form of artificial lift.

For a large project, reservoir models may be used to

predict expected inflow conditions of the expected life of theproject.

Reservoir Fluid. The characteristics of the reservoir fluidmust also be considered. Paraffin is a much more difficultproblem for some kinds of lift than for others. Sandproduction can be very detrimental to some types of lift. The

producing gas-liquid ratio (GLR) is very important to the liftdesigner. Free gas at pump intake is a significant problem toall of the pumping lift methods but is beneficial for gas lift,which simply supplements the lift energy already contained inthe producing gas.

Long Term Reservoir Performance and Facility

Constraints. Two approaches have frequently been taken inthe past to account for long term reservoir performance. In ouropinion, both of these approaches are extreme and wrong.

In some cases, we predict long term reservoir performanceand install artificial lift equipment that can handle the wellover its entire life. This frequently lead to the installation of

oversized equipment in the anticipation of ultimatelyproducing large quantities of water. As a result, the equipment

may operate at poor efficiency due to under-loading over asignificant portion of its total life.

The other extreme is to design for what the well isproducing today and not worry about tomorrow. This can lead

to change after change after change in the type of liftequipment installed in the hole. We may operate efficientlyshort term but spend large amounts of capital dollars inchanging equipment. For instance, the changing reservoirconditions with time shown in Figure 3 would have to be

carefully considered in sizing artificial lift equipment forcurrent conditions and for some selected future period of time.

Reference 14 is concerned in detail with timing of artificial liftmethods.

In a new field development, the fluid handling requirementcan significantly increase the size and cost of the facilitiesrequired to produce the field. With beam or electricsubmersible pumps, only the produced fluid is handledthrough the facilities. With gas lift, the injection gas

compression and distribution facilities and additional gas inthe production adds to the facilities. With hydraulics, thepower fluid pumps, power fluid injection lines and additional

power fluid, many times combined with the production fluidadds to the fluid handling costs.

The design engineer must consider both long term and

short term aspects. Our aim is to maximize the present valueprofit of the operation. The highest present value profit may ormay not result from greatest production rate available from thewell and may or may not anticipate a lift system change in the

future. Many of the introductory comments and observationsin the proceeding discussion will be included in lists ofadvantages/disadvantages, expert systems and other types ofselection analyses discussed in following sections.

Types of Artificial Lift.The various major forms of artificialift are shown schematically in Figure 4. There are othermethods as well which will be mentioned as appropriate in the

following discussions, such as the ESPCP for pumping solidsand viscous oils. This system has a PCP pump with the motorand other components similar to an ESP. Other methodsinclude long stroke modifications of beam pump systems.

The selection of the lift method should be a part of the

overall well design. Once the lift method is selectedconsideration should be given to the size of the well borerequired to obtain the desired production rate. More than oncea casing program has been designed to minimize well cost and

then find that the desired production could not be obtainedbecause of the size limitation on the artificial lift equipmentEven if production rates can be achieved, smaller casing sizescan lead to higher long term production costs such as well

servicing and gas separation problems. If oil prices are low, iis tempting to select a small casing size to help with currenteconomics. On rare occasions wells are drilled with the futurelift methods in mind.

The following sections will further detail each method of

lift with major advantages and disadvantages and how theymay be expected to perform in various well environments.

Selection by Consideration of Depth/Rate System

Capabilities.One selection criteria is the range of depth andrate where particular lift types can function (Figure 5). This

chart is a slightly modified version of the original chartpublished by R. Blais, Pennwell. The depth-rate ranges inFigure 5 are approximate and there are many exceptions tothem, but they provide a quick idea of what systems are

available to lift with certain rates and from certain depthsParticular well conditions can lead to wide divergences fromthe initial selection from using these charts alone. Specific

designs are recommended for specific well conditions todetermine the rates possible from given depths.

Note how Figure 5 shows hydraulics systems can pumpfrom the greatest depths due to the U tube balancing ofproduced fluid pressures with the hydraulic fluid pressureGas lift has a wide range of production capacity. Beam pump

produces more from shallower depths and less from deeperdepths due to increasing rod weight and stretch as depthincreases. ESPs are depth limited due to burst limitations onhousings and energy considerations for long cables, but can


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SPE 52157 SELECTION OF ARTIFICIAL LIFT 3

produce large production rates. Plunger lift is for low liquidrates to primarily clear liquids from gas wells. Plunger is notparticularly depth limited, due to increased energy storage inthe casing annulus as depth increases.

Details of Major Systems.

Sucker Rod Pumping. Sucker rod pumping systems arethe oldest and most widely used type of artificial lift for oil

wells. Figure 6 shows a schematic of a typical rod pumpingsystem.

About 85 percent of all artificially lifted wells in the USAare produced by rod pumps. This is also true in some areas of

S. America and Canada. About 80 percent of all oil wells arestripper wells, making less than 10 bopd. A vast majority ofthese stripper wells are lifted with sucker rod pumps. Of theremaining 20 percent, about 27 percent are rod pumped, 52percent gas lifted and the remainder lifted with ESPs,

hydraulic pumps and other methods of lift.Although these statistics are ca. 1980, and are no doubt

somewhat different today, they indicate the dominance of rodpumping for onshore operations. For offshore and higher rate

wells, the use of ESPs and especially gas lift increasesdramatically.

Sucker rod pumping systems should be considered fornew, low volume stripper wells because operatingpersonnel are usually familiar with these mechanically

simple systems and can operate them more efficiently.Inexperienced personnel also can often operate rod pumpsmore effectively than other types of artificial lift. Suckerrod pumping systems can operate efficiently over a widerange of well producing characteristics. Most of these

systems have a high salvage value.

Sucker rod systems also should be considered for liftingmoderate volumes from shallow depths and smallvolumes from intermediate depths. It is possible to lift1,000 barrels from about 7,000 feet and 200 barrels from

approximately 14,000 feet (special rods may be required).If the well fluids contain hydrogen sulfide, sucker rodpumping systems can lift 1,000 barrels of liquid per dayfrom 4,000 feet and 200 barrels per day from 10,000 feet

(exclusive of other mitigating conditions).

Most of the parts of the sucker rod pumping system aremanufactured to meet existing standards, which havebeen established by the American Petroleum Institute.Numerous manufacturers can supply each part, and all

interconnecting parts are compatible. The sucker rod string, parts of the pump and unanchored

tubing are continuously subjected to fatigue. Therefore,the system must be more effectively protected againstcorrosion more than any other lift system to insure longequipment life.

Sucker rod pumping systems and well dog-leg severityare often incompatible. Deviated wells with smoothprofiles may allow satisfactory sucker rod pumping.

The ability of sucker rod pumping systems to lift sand islimited.

Paraffin and scale can interfere with the efficientoperation of sucker rod pumping systems.

If the gas-liquid separation capacity of the tubing-casingannulus is too low, or if the annulus is not usedefficiently, and the pump is not designed and operated

properly, the pump will operate inefficiently and tend togas lock.

One of the disadvantages of a beam pumping system isthat the polished rod stuffing box can leak. However, ifproper design and operating criteria are considered andfollowed, that disadvantage can be minimized.

If the system is not sized to the well productivity and isover-pumped without POC (pump-off control)

mechanical damage and inefficient pump operation wiloccur.

Electrical Submersible Pumping (ESP). As an examplearea where ESPs are applied extensively, THUMS Long

Beach Company was formed in April 1965 to drill, developand produce the 6479 acre Long Beach Unit in Wilmington

Field, Long Beach, California. It was necessary to choose thebest method of lift for approximately 1100 deviated wells ovea 35 year contract period from four (4) man-made offshoreislands and one (1) onshore site. A schematic of a typical ESPsystem is shown in Figure 7.

Advantages.

Adaptable to highly deviated wells - up to 80. Adaptable to required subsurface wellheads 6' apar

for maximum surface location density.

Permit use of minimum space for subsurface controls

and associated production facilities. Quiet, safe and sanitary for acceptable operations in

an offshore and environmentally conscious area.

Generally considered a high volume pump - providesfor increased volumes and water cuts brought on bypressure maintenance and secondary recoveryoperations.

Permits placing well production even while drillingand working over wells in immediate vicinity.

Disadvantages.

Will tolerate only minimal percents of solids (sand)production.

Costly pulling operations to correct downholefailures (DHFs).

While on a DHF there is a loss of production duringthe time well is covered by drilling operations inimmediate vicinity.

Not particularly adaptable to low volumes - less than150 B/D gross.

Long life of ESP equipment is required to keep productioneconomical with high water cuts, approximately greater than


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90%. Required improvements and recommendations basedupon experience are as follows:

Specify new stages and shaft in a rebuilt pump. Do notreuse pumps except in a test case.

Pump designs are normally floating but usecompression to handle abrasives or to provide downthrust resistance if cycling or gas slugging is expected or

if uncertain about rate - improves rate flexibility. Low amperage, high voltage motors are preferred. Motors run at 60F above ambient. Above 200F use

high temperature equipment.

Reuse motors in cool wells if cumulative run life < 1,200days and passes QC inspection.

Use a modular (3 chamber -BSBSL) or a tandem (4chamber) seal configuration for redundancy anddeviation angle resistance. Never reuse a seal chamber.

Use high temperature elastomers and oil wherewarranted.

Cable best success is with 5KV, #4 solid conductor(solid preferred to stranded) with barrier and braid and

heavy armor. Use cable with lead sheathing in high H2Sconditions.

Taped cable splices are preferred to molded.

Good cable handling practices are imperative in reducingcable failures. Pull slow to prevent decompressionproblems. Use 2 pre -formed super-bands especiallyin deviated wells. Use no more than 7 splices per stringincluding motor lead extension and lower mandrel

connection. Try not to place splice near fluid level. Placemotor lead extension/round splice well above pumpoutlet (~200) to keep cool. Use new cable with nosplices in hot wells.

The latest generation of motor controllers can collect andstore operational and forensic data (amps, kWh usage,phase leakage, restart records, backspin, rotation, etc.)and can provide restart lockout during backspin.

The Electrical Submersible Progressive Cavity Pump

(ESPCP).A schematic of a progressive cavity pump (PCP) isshown in Figure 8. The PCP has a rotating metal rotor and aflexible rubber molded stator. The rotating stator forms acavity that moves up as the rotor turns. The pump is well

suited for handling solids and viscous fluids as the solids thatmove though the pump may deflect the rubber stator but donot abrade or wear the stator or rotor to any appreciabledegree. In the past, most PCPs were powered by rotating rodsdriven from the surface with a hydraulic or electrical motor.

Introduced in 1936, the PCP is of simple design andrugged construction, and its low operating speeds enable thepump to maintain long periods of downhole operation if it isnot subjected to chemical attack, excessive wear, or installed

at depths greater than about 4000 feet. The pump has only onemoving part downhole, with no valves to stick, clog or wearout. The pump will not gas lock, can easily handle sandy andabrasive formation fluids and it not plugged by paraffin,

gypsum or scale.With this system, the rotating rods would wear and also

wear the casing. The rotating rods would wind up on star

and unwind on the shut-down. Rotating rods must be sealedat the surface and many installations would have oil leaks atthe surface.

To alleviate the problems with the conventional rotating

rod PCP systems, the ESPCP system is being made availableThis is not a new system. It has been run in Russia for anumber of years and also was available from ODI (ESPvendor) a number of years ago. The new ESPCP system(Figures 9-10) has a number of advantages over the rotating

sucker rod systems.As shown in Figures 9 and 10, the PCP pump is located on

top of the assembly. There is problem of rotating the eccentricrotor with the motor shaft because of possible vibration hencea flexible connection is used. There is a seal section as in an

ESP assembly to protect the underlying motor from well-borefluids and also to accommodate and thrust in the internalthrust bearing. Because the PCP usually turns around 3-600

rpm and the ESP motor turns around 3500 rpm under loadthere must be a way of reducing speed before the shaftconnects to the PCP.

Methods in use from the various manufacturers includeusing a gear box to reduce the 3500 rpm to acceptable speedsor using higher pole motors with lower synchronous speeds to

allow the PCP to turn at operational speeds. The motor islocated on the bottom of the assembly so fluids can pass themotor and provide cooling as in the conventional ESP. Sincethe ESPCP is not rod connected, it can be run into deviated or

horizontal wells. Some manufacturers refer to this system asthe PCSPS (Progressive Cavity Submersible Pump System) orthe ESPCP (Electrical Submersible Progressive Cavity Pump)

Advantages.

The pumping system can be run into deviated andhorizontal wells.

The pump handles solids in production well.

The pump handles viscous production well.

Several of the components are off the shelf ESPcomponents.

The production rates can be varied with use of avariable speed controller (VSC).

There is one modification of this system whereby the

pump can be wire-lined out of the hole leaving the motor andthe rest of the system behind. This is desirable because the

pump is likely to have the shortest run life.

Disadvantages. The unit does not tolerate heat due to the softening

of the stator material.

Gas must be separated to increase efficiency. It wilnot gas lock but if ingesting large amounts of gas

continuously, or if pumped off, it will overheat anddamage will occur to the stator.


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If the unit pumps off the well, the stator will likelybe permanently damaged.

The gearbox is another source of failure if well-borefluids or solids leak inside.

This pump is suited for deviated wells and can be run in

most locations of a horizontal well.

Summary. If you have a low pressure well with solidsand/or heavy oil, and the well temperature is not high, thenyou could consider an ESPCP. If this is offshore or wherepulling the well is very expensive, you could consider theoption of the ESPCP that allows wire-lining out a failed pump

from the well while leaving the seal section, gear box, motor,and cable still installed for additional usage. This modificationis in use in THUMS in Long Beach, CA.

Hydraulic Pumping. There are two kinds of hydraulicpumps currently on the market; (1) positive displacementpumps and (2) jet pumps. The positive displacement pump

consists of a reciprocating hydraulic engine directly coupled

to a pump piston or pump plunger (Figure 11). Power fluid(oil or water) is directed down the tubing string to operate theengine. The pump piston or plunger draws fluid from the well

bore through a standing valve. Exhausted power fluid andproduction can be returned up a separate tubing string or upthe casing.

The jet pump is also shown in Figure 11. High pressurepower fluid is directed down the tubing to the nozzle where

the pressure energy is converted to velocity head. The highvelocity-low pressure power fluid entrains the productionfluid in the throat of the pump. A diffuser then reduces thevelocity and increases the pressure to allow the commingled

fluids to flow to the surface.

Combining the power fluid and production is called anOpen Power Fluid system. If production and power fluid arereturned up separate tubing, then this is a Parallel installationwith gas vented through the casing annulus to the surface. A

Casing installation requires the pump to handle the gas. Bothtypes are used with positive displacement pumps and with jetpumps. In fact, most bottom hole assemblies canaccommodate interchangeability of jet pumps and positive

displacement pumps.A Closed Power Fluid arrangement is where power fluid is

returned to the surface separately from the production.Because the jet pump must commingle the power fluid andproduction, it cannot operate as a Closed Power Fluid pump.

The most outstanding feature of hydraulic pumps is thefree pump (Figure 12). The drawing on the left of Figure 12shows a standing valve (inserted by wireline) at the bottom ofthe tubing and the tubing filled with fluid. In the second

drawing, a pump has been inserted in the tubing and is beingcirculated to the bottom. In the third drawing the pump is onbottom and pumping. When the pump is in need of repair, it iscirculated to the surface as shown in the drawing on the right.The positive displacement pump, the jet pump and the closed

power fluid system previously shown above are all freepumps.

Surface facilities required are a power fluid cleaning

system and a pump. The most common cleaning systems aresettling tanks located at the tank battery. Sometimes cyclonede-sanders are used in addition to settling tanks. In the lasfew years well site power plants have been very popular

These are separators located at the well with cyclone desanders to remove solids from the power fluid.

Surface pumps are most commonly triplex plunger pumpsOther types are quintiplex plunger pumps, multistagecentrifugal pumps and canned electric submersible pumps

Surface pressure required is usually in the 1500-4000 PSIrange. It is important to specify 100% continuous duty for thepower fluid pump at the required rate and pressure. Lowvolume (2500 psi)

use plunger type pumps.Approximate maximum capacities and lift capabilities for

positive displacement pumps are shown in Table 3. In somecases, two pumps have been installed in one tubing string

Seal collars in the bottom hole assembly connect the pumps inparallel hydraulically. Thus, the maximum displacemenvalues shown above are doubled.

A tabulation of capacity vs. lift is not practical for jepumps because of the many variables and their complex

relationships. To keep fluid velocities below 50 ft/sec. insuction and discharge passages, the maximum productionrates vs. tubing size for Jet FREE PUMPS are approximatelyas shown in Table 4.

Fixed type jet pumps (those too large to fit inside the

tubing) have been made with capacities to 17,000 B/D. Evenlarger pumps can be made. Maximum lifting depth for jepumps is around 8000-9000 feet if surface power fluid

pressure is limited to 3500 PSI. The maximum capacitieslisted above can be obtained only to about 5000-6000 feetThese jet pump figures are only guidelines because welconditions and fluid properties can have significant influenceson them. It should also be noted that the maximum capacitieslisted above are for high volume jet pumps that require bottom

hole assemblies that are not capable of also accommodatingpiston pumps.

Advantages. FREE PUMP - Being able to circulate the pump in

and out of the well is the most obvious andsignificant feature of hydraulic pumps. It is

especially attractive on offshore platforms, remotelocations, populated, and agricultural areas.

Deep Wells - Positive displacement pumps arecapable of pumping depths to 17,000 feet, anddeeper. Jet pumps can be run to 20,000 feet withdesign target of 25% submergence at intake.

Speed Control- By changing the power fluid rate topumps, production can be varied from 10 percent to


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100 percent of pump capacity. The optimum speedrange is 20 to 85 percent of rated speed.

Crooked Wells- Deviated wells typically present noproblem to hydraulic free pumps. Jet pumps can

even be used in TFL installations.

Sand Production- jet pumps, because they have nomoving parts, can handle sand and other solids with

hardened nozzle throats. Viscous Oils - Positive displacement pumps can

handle viscous oils very well. The power fluid can

be heated or it can have diluent added to further aidgetting the oil to the surface.

Corrosion- Corrosion inhibitors can be injected intothe power fluid for corrosion control.

Disadvantages. Power Fluid Cleaning - Removing solids from the

power fluid is very important for positive

displacement pumps. Surface plunger pumps arealso affected by solids in the power fluid. Jet pumps,

on the other hand, are very tolerant of poor powerfluid quality.

Pump Life - Positive displacement pumps, onaverage, have shorter life between repairs than Jet,sucker rod and electric submersible pumps. Mostly,this is a function of the quality of power fluid, butalso, on average, they are pumping from greater

depths which is also a factor. Jet pumps, on the otherhand, have very long pump life between repairswithout solids or if not being subjected to cavitation.

Bottom Hole Pressure - Positive displacementpumps can pump to practically zero bottom holepressure in the absence of gas interference and other

problems (lowest bottom hole pressure is a gasgradient to the pump depth plus casing pressure) Jetpumps cannot pump to low intake pressures. Jetpumps require approximately 1000 PSI bottom hole

pressure when set at 10,000 feet and approximately500 PSI when set at 5000 feet.

Skilled Personnel - Positive displacement pumpsgenerally require more highly skilled operatingpersonnel, or perhaps, just more attention, than jet

pumps and other types of artificial lift. There aretwo reasons for this. First, pump speed needs to bemonitored daily and not allowed to becomeexcessive. Secondly, power fluid cleaning systems

need frequent checking to keep them operating attheir optimum effectiveness.

To answer the question, when do you use jet pumps andwhen do you use positive displacement pumps?, our answeris: Use jet pumps if the flowing (pumping) bottom hole

pressure is adequate (see disadvantage No. 3 above).

Gas Lift. Gas lift dominates the USA Gulf Coast and is

used extensively around the world. Most of these wells are on

constant flow gas lift. Thus, the questions: Why choose gaslift?, Where do you use constant flow? and When do youselect intermittent lift?

Constant Flow Gas Lift.A schematic of a gas lift systemis shown in Figure 13. Constant flow gas lift is recommended

for high volume and high static bottom hole pressure wells

where major pumping problems will occur. It is an excellentapplication for offshore classic-type formations with waterdrive, or waterflood reservoirs with good productivity indices

(PIs) and high gas-oil ratios (GORs). When high pressuregas is available without compression or where gas is low incost, gas lift is especially attractive. Constant flow gas liftsupplements the produced gas with additional gas injection tolower the intake pressure to the tubing, including lowering

formation pressure.A reliable, adequate supply of good quality high-pressure

lift gas is mandatory. This supply is necessary throughout theproducing life if gas lift is to be effectively maintained. In

many fields the produced gas declines as water cut increases

requiring some outside source of gas. The gas lift pressure istypically fixed during the initial phase of the facility designand as the water cut increases the depth of lift is decreased notallowing the gas lift system to obtain the desired flowing

bottom hole pressure. Also the wells will produce erraticallyor not at all when the lift supply stops or pressure fluctuatesradically. Poor quality gas will impair or even stopproduction. Thus, the basic requirement for gas must be me

or other artificial lift means should be installed.Constant flow gas lift imposes a relatively high back

pressure on the reservoir compared to pumping methods andis at best only moderately efficient. The high back pressuremay significantly reduce production as compared with some

pumping methods and poor efficiency significantly increasesboth capital cost and operating energy costs.

Advantages.

Gas lift is the best artificial lift method for handlingsand or solid materials. Many wells make some sandeven if sand control is installed. The produced sand

causes almost no mechanical problem to the gas liftvalve; whereas, only a little sand plays havoc withmost pumping methods.

Deviated or crooked holes can be gas lifted withonly minor lift problems. This is especially

important for offshore platform wells which are

directionally drilled. Gas lift permits the use of wireline equipment and

such equipment is easily and economically servicedThis feature allows for routine repairs through the

tubing.

The normal design leaves the tubing full openingThis permits use of BHP surveys, sand sounding andbailing, production logging, cutting, paraffin, etc.


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High formation GORs are helpful rather than beinga hindrance. Thus in gas lift, less injection gas isrequired; whereas, in all pumping methods, pumpedgas reduces efficiency drastically.

Gas lift is flexible. A wide range of volumes and liftdepths can be achieved with essentially the samewell equipment. In some cases, switching to annular

flow can also be easily accomplished to handleexceedingly high volumes.

A central gas lift system can be easily used toservice many wells or operate an entire field.Centralization usually lowers total capital cost andpermits easier well control and testing.

Gas lift has a low profile. The surface wellequipment is the same as for flowing wells except

for injection gas metering. The low profile is usuallyan advantage in urban environments.

Well subsurface equipment is relatively inexpensiveand repair and maintenance of this subsurfaceequipment is normally low. The equipment is easily

pulled and repaired or replaced. Also major wellworkovers occur infrequently.

Installation of gas lift is compatible with subsurfacesafety valves and other surface equipment. Use ofthe surface controlled subsurface safety valve with

the 1/4-inch control line allows easy shut-in of thewell.

Gas lift will tolerate some bad design assumptionsand still work. This is fortunate since the spacingdesign must usually be made before the well is

completed and tested.

Disadvantages. Relatively high back pressure may seriously restrict

production in continuous gas lift. This problembecomes more significant with increasing depthsand declining static BHPs. Thus a 10,000 foot wellwith a static BHP of 1000 psi and a PI of 1.0 would

be difficult to lift with the standard constant flowgas lift system. However, there are some specialschemes that could be tried for such wells.

Gas lift is relatively inefficient, often resulting inlarge capital investments and high energy operating

costs. The cost of compressors is relatively high andare often long delivery items. Costs in 1981 werefound to be $500 to $600 per horsepower for typical

land locations and $1000 to $1400 per horsepowerfor offshore packages. The compressor presentsspace and weight design problems when used onoffshore platforms. Also, the cost of the distributionsystems onshore may be significant. Increased gasusage also may increase the size of flow line and

separators needed.

Adequate gas supply is needed throughout life ofproject. If the field runs out of gas or if gas becomes

too expensive, one may have to switch to another lifmethod. In addition, there must be enough gas foreasy start-ups.

Increasing water cut increases the flowing bottomhole pressure with a fixed gas lift pressure. At somewater cut, another form of lift, such as ESPsshould be evaluated to increase production be

reducing the flowing bottom hole pressureespecially if the produced gas is low.

Operation and maintenance of compressors can beexpensive. Skilled operators and good compressormechanics are required for successful and reliableoperation.

There is increased difficulty when lifting lowgravity (less than 15 API) crude due to greater

friction. The cooling effect of gas expansion furtheraggravates this problem. Also the cooling effect willcompound any paraffin problem.

Low fluid volumes in conjunction with high watercuts (less than 200 BPD in 2-3/8" OD tubing)

become less efficient to lift and frequently severeheading is experienced.

Good data are required to make a good design. Such datamay not be available and you may have to continueoperations with an inefficient design that does not

produce the well to capacity.

Potential gas lift problems that must be resolved.

Freezing and hydrate problems in injection gas lines Corrosive injection gas. Severe paraffin problems. Fluctuating suction and discharge pressures. Wireline problems. Dual artificial lift frequently results in poor lift

efficiency.

Changing well conditions, especially decline in BHPand PI.

Deep high volume lift. Valve interference multi-pointing. Emulsions forming in the tubing

Intermittent Gas Lift. Intermittent gas lift method isgenerally used on wells that produce low volumes of fluid(~


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major factors to be considered are similar. Only thedifferences will be highlighted in the ensuing discussion.

Advantages.

Intermittent gas lift has a significantly lowerproducing BHP than the constant flow methods.

It has the ability to handle low volumes of fluid with

relatively low production BHPs.

Disadvantages.

Intermittent gas lift is limited to low volume wells.For example an 8,000 foot well with 2" nominaltubing can seldom be produced at rates of over 200BPD with an average producing pressure much

below 250 psig. Smaller sizes of tubing have even alower maximum rate.

The average producing pressure of a conventionalintermittent lift system is still relatively high whencompared to rod pumping. However, the producing

BHP can be reduced by use of chambers. Chambers

are particularly suited to high PI, low BHP wells. The output to input horsepower efficiency is low.

More gas is used per barrel of produced fluid thanwith constant flow gas lift. Also the slippage

increases with depth and water cut making the liftsystem even more inefficient. However, slippagecan be reduced by use of plungers. In general if thecycle time allows time for the plunger to fall, thenplunger should be used with intermittent lift if not

solids are present.

The fluctuation in rate and BHP can be detrimentalto wells with sand control. The produced sand mayplug the tubing or standing valve. Also surface

fluctuations cause gas and fluid handling problems. Intermittent gas lift requires frequent adjustments.

The lease operator must alter the injection rate andtime period routinely to increase the production andkeep the lift gas requirement relatively low.

Conclusion. Gas lift has numerous strengths that in manyfields make it the best choice of artificial lift. However, there

are limitations and potential problems to be dealt with. Onehas a choice of using either constant flow for high volumewells or intermittent for low volume wells and there is littledifficulty in switching from one to the other. In addition, gaslift can be used to kick off wells, unload water from gas wells,

or back flow injection wells. Gas lift deserves seriousconsideration as a means of artificial lift.

Other Methods of Lift.There are other methods of lift thatwill not be discussed in a paper of this length. Plunger lift iscommonly used to remove liquids from gas wells to maintaina low gradient in the tubing. There is a chamber pump that

relies on gas pressure to periodically empty the chamber andforce the fluids to the surface with no gas mixing.

Rather than try to examine all possible forms of lift, therest of the discussion below will be relegated to methods thacan be used to select the best form of lift for a particular

application. The methods should be applicable to any form olift under consideration.

Selection by Advantages and Disadvantages.Although the

previous sections detailed the major systems of artificial lifand listed some advantages/disadvantages, there are othermore detailed listings of advantages and disadvantages.

Reference 1 by Clegg, Bucaram & Hein is the mos

extensive and useful listing of the various advantages anddisadvantages of various lift systems under a broad range ofcategories. Some of their information is open to discussionsuch as their low limit on gas lift with viscous fluids, but in

general it is the best available list of artificial lift advantagesand disadvantages.

Tables 1 and 2 after Brown (Ref. 2) do provide a usefusummary of the various advantages and disadvantages of thevarious lift systems that were described briefly in the

proceeding sections. It is probable that many artificial lifsystems have been and can be selected by using tables similarto those generated by Clegg, Bucaram & Hein (Ref. 1) or theTables 1 & 2 repeated here from Brown (Ref. 2). However

there are other important considerations beyond a list oadvantages/disadvantages. Reference 3 is a brief summary ofadvantages/disadvantages and selection criteria for various lifsystems separately presented by experts in a forum discussion

Selection by Expert Programs.An advancement that shouldbe a step above a simple list of advantages/disadvantages isthe advent of expert programs or computerized lift selection

programs. These programs include rules and logic so they wil

branch to select the best system of lift as a function of userinput of well and operating conditions. References 4-6 arepublications dealing with expert systems for the selection o

artificial lift systems.Reference 4 describes an expert system with selection

criteria on:1. Sucker rod2. Hydraulic pump3. ESP4. Progressive pump5. Continuous gas lift6. Intermittent gas lift7. Intermittent gas lift with plunger

8. Constant slug injection gas lift9. Chamber gas lift10. Conventional plunger lift

The program contains; an (1) Expert Module, a (2) DesignModule, and a (3) Economic Module. Module 1 is an expert

module that includes a knowledge base structured from humanexpertise, theoretical written knowledge available and knownrule of thumb type calculations. Module 2 incorporatessimulation design and facility component specification

programs for all lift methods considered. Module 3 is an


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economics evaluation module that includes a costs data base,and cost analysis programs to calculate lift profitability.

Module 1 ranks the methods and also issues somewarnings, some of which may rule out high ranked methods.

Module 2 contains a suite of design methods with advice tofollow from Module 1. Module 3 utilizes the designs andexpected production rate to calculate profitability using

evaluation parameters such as net present value and rate ofreturn. It also includes investment costs and repair andmaintenance costs.

Reference 5 describes the program AL which decides,from user input, what system among gas lift, hydraulic, suckerrod or ESP pumping systems, is best for particular conditions.

Problems such as sand, paraffin, crooked hole, corrosion,small casing, flexibility, and scale are used, with the storedknowledge base and user input, to allow the program to rankby score, the most appropriate method of lift for particular

conditions. Details of the programs input, structure, andoutput are contained in the reference.

Reference 6 describes another expert system, which is very

encompassing in scope. The reference describes the OPUS(Optimum Pumping Unit Search) program, later described

commercially as the Artilip program. The program consists of;(a) a knowledge base containing the complete set of specificinformation on the domain of expertise; (b) an inferenceengine using the data and heuristics of the knowledge base to

solve the problem and (c) interactive modules enabling verysimple use of the expert system.

The structure of the rules in Reference 5 is of the form,

if (condition) then ( type of process)

For each process (i.e., lift method) , a suitability

coefficient (SC) from 1 to + 1 for the given condition isdefined, where SC = 1 eliminates the process from further

consideration and SC = +1 indicates a process well suited tothe given condition.

For example, the simple expression

if (Pump Temperature > 275F) then (ESP), -1

defines a rule that eliminates ESPs if the pump temperatureexceeds 275F (although this rule would have to be updated toinclude use of hot line ESPs).

Intermediate values can be used to refine the system andmethods are presented for combining the coefficients into a

single coefficient. The program can combine the suitabilitycoefficients into one value for over-all evaluation. Other

details for the knowledge representation and the technicaland economic evaluation are given in the paper.

Another interesting feature (Ref. 6) is the presentation ofeconomical data for annual costs to be incurred by various liftsystems. The costs are presented in bar graphs showing how

the component costs would occur above the well head orsubsurface. For instance, much of the possible re-occurringcosts for ESPs can be subsurface whereas for gas lift, other

than wireline work, larger repair and servicing costsassociated with compressors would be above ground.

Selection by Net Present Value (NPV) Comparison. Amore complete selection technique will depend upon the life-time economics of the available lift methods. The economics

in turn depend, for example, upon the failure rates of the

system components, fuel costs, maintenance costs, inflationrates, anticipated revenue from produced oil and gas and otherfactors that may vary from system to system. Reference 7-9 byEtherton, et. al., by Smith and by Kol, et. al. are example

studies in selection that follow economically guided selectiontechniques.

References 10-16 provide various references on artificialift in general, efficiency of lift methods, selection techniques

and limitations on various lift systems.This section will illustrate the economic concepts for a

low-rate and high rate example. Methods considered are ESPgas lift, hydraulic pump and rod pump. It will use an enhanced

method of analysis similar to calculation methods available in

Ref. 17. The equations used in the following example analysisare given in detail in the Appendix.

In order to use the NPV comparison method, the user musthave a good idea of the associated costs for each system. This

requires that the user evaluate each system carefully for hisparticular well and be aware of the advantages/disadvantagesof each system and additional equipment (i.e., additionacosts) that may be required. Since energy costs are included in

the NPV analysis, an optimal design for each feasible methodmust be determined before running the NPV analysis.

These factors force the user to consider all the selectionmethods discussed previously to generate the necessaryinformation for the NPV analysis.

Low-Rate Example. Consider an example well with thefollowing characteristics.

Vertical Depth to Perforations 6000 ftSeparator Pressure 100 psigSurface Temperature 100 FCasing Size 7 inchTubing Size 3.500 inch, Gas Lift

2.875 inch, OtherMethodsWater Cut 50 %Oil Gravity 30 API

Gas Gravity .7Water Gravity 1.03

Produced GOR 400 scf/bblBubble Point 2227 psigStatic Reservoir Pressure 2000 psig

Productivity Index 1 STB/psiThere are common costs and economic variables that are

the same for all the different methods.Fixed Costs 300 $/month

Fluid Disposal .35 $/bbl waterElectricity .05 $/kW-hrOil Revenue 12 $/bbl


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Gas Revenue 1.25 $/MscfInflation Rate 3 %/yr.Discount Rate for Present Value 8 %/yr.Oil Revenue Increase 1 %/yr.

To calculate the expected lifetime of the well, reasonablereservoir production estimates must be supplied. For thisexample, we assume that all lift methods (ESP, Gas Lift,

Beam Pump & Hydraulics) will produce initially at the samerate, 1000 bbl/day with 50% water cut and 400 GOR. Thereservoir is assumed to decline immediately at 20 %/yearreduction in oil rate. Water cut is assumed to increasemaintaining the rate constant (water injection). At 90% watercut, the simulation is stopped. The GOR is assumed to remain

constant for this example.The actual possible initial production rate would differ for

each method, but for comparison purposes and to illustrate theconcepts, a rate of 1000 bbl/day for each method is assumed.

Different rates would possibly require different productionfacilities and different initial costs. Thus each method shouldbe optimized and the associated required costs included in the

economic analysis.Method specific costs must also be included as shown in

Tables 5-9.

Run Life Tables.The average pump run life for the pumping

systems, and the injected gas volume for gas lift, is required toestimate the life-time costs for the different methods. Thevalues assumed for this example are listed in Table 10. Thelast value in each table is used for subsequent years.

The different methods are compared by calculating the net

present value (NPV) income as a function of time until theproduction rate decreases to the abandonment rate. This givesa direct comparison of the different methods in terms of thenet revenue the well would be expected to produce.

Figure 14 shows results for the assumptions of thisexample. Rod pumping would be the best method, showing tobe slightly more profitable than ESP, over the ~7 year life ofthe well. The analysis is stopped at ~7 years when 90% watercut is reached. These analyses also can be run for depleting

rates.The NPV and total lifetime costs for each method are

summarized in Table 11. The operating costs are significant,ranging from 14-26% of the NPV for this low rate example.

Reduction in operating costs could therefore be a significantfactor in selecting the optimum lift method.

To re-emphasize, the results will depend upon theparticular cost related data for each method. For this case,

however, it is likely that rod pump or ESP would be the mosteconomical method depending on the detailed cost data, andgas lift and hydraulic pump would not be recommended.

High Rate Example.A well with productivity index PI =24 bbl/d/psi is considered. Rod pumping cannot deliver therates required for this design and is eliminated fromconsideration. Artificial lift designs with jet pump, ESP and

gas lift yield only are considered.Production GOR and water cut is constant at 100 scf/bbl

and 1% respectively. Abandonment rate is 500 bbl/d, oil +

water. The reservoir oil production declines at 20% yearOperation and equipment specific costs are provided inTables 12-15.

Fixed Costs 1000 $/monthWater Disposal .15 $/bblElectricity .05 $/kW-hrOil Revenue 12 $/bbl

Gas Revenue 1.25 $/MscfInflation Rate 3 %/yr.Discount Rate for Present Value 8 %/yr.Oil Revenue Increase 1 %/yr.

Run Life Tables. The average pump run life for thepumping systems, and the injected gas volume for gas lift, isrequired to estimate the life-time costs for the differen

methods. The values assumed for this example are listed inTable 16. The last value in each table is used for subsequentyears.

Figure 15 shows results for the assumptions of thisexample. jet pump would be the best method, producing abou

$4,000,000 more NPV than the ESP and $11,000,000 more

than gas lift over the life of the well. Although the curvesshow that the NPV is near the point of no further increase, thecurves are terminated at the point where the abandonment rate

of 500 bpd occurs.The NPV and total lifetime costs for each method are

summarized in Table 17. The operating costs are relativelyinsignificant for this high rate case, ranging from 1.6 2.0 %of the NPV for this high rate example. Operating costs

therefore are not as significant a factor in selecting theoptimum lift method for high rate wells.

Run Life Information.As shown in the above examples ofselection of artificial lift, one of the main factors in many

cases is knowing what the failure rates of are for the variouspossible systems or the individual components of the systems

Some typical examples of failure rates and costs are discussedhere.

Figure 16 shows failure rates from a group of 500+ beampumped wells over a period of years. The costs for downholelift replacement and servicing are shown over the bars on the

figure.Figure 17 shows a pie chart breakdown of the major

causes for failure of the beam pump systems that went into theaccumulation of the failure rate data plot. If a lift selection

study is needed, data such as this for a field of similarconditions would be very helpful in evaluating beam pump as

a candidate and being able to compare beam pump to othersmethods of lift.

The conditions for the data presented here are a mix of

deep and shallower wells. The deep wells average abou8,880'-9,200'. They make about 926 BOPD and 8,562 BWPDThe unit size averages out to be close to a 640. The shallowerwells will average to be about 4,200' deep. They make 2,885

BOPD and 37,577 BWPD. For the pumping unit they averageout to be about a 320. Different field conditions and methodsof operations will result in different failure rates and a


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different distribution of failed components.Figure 18 shows run lives of ESPs in the THUMS

operations offshore Long Beach, CA. There have been anumber of improvements to the submersible system at

THUMS that have been implemented over a 16 year periodthat are responsible for increasing the mean time betweenfailures from 320 days in 1983 to over 1100 days in 1997.

These statistics are based on any cause that required thedownhole equipment to be pulled. Table 18 gives a summaryof the conditions in this operation.

Figure 19 shows ESP run lives for various fields. Thisdata was collected and presented in Reference 6 below for astudy for a study of artificial lift feasibility and what method

to use in a Siberian location. Table 19 shows one panel ofinformation collected for ESPs and details the costs andequipment for a 900 bpd installation based on data collectedfrom other similar fields. This application detailed in

Reference 6 was for deep deviated wells drilled from onshorelocations in a marshy environment. Component service livesare shown in Table 20. Targets and downside potentials were

established for this study as shown in Figure 19.Reference 18 also includes various run life information

and selection criteria. Swan Hills (Alberta), Milne Point(Alaska), the Amoco Congo field, the THUMS E. Wilmingtonfield, and the Amoco N. Sea field, the Montrose field wereused to help predict run lives for the Priobskoye field in

Siberia. More information on the conditions present in thesefields can be found in Reference 6. The learning curveaspect of these fields is costly showing the time required tocome up to reasonable operational lives for the ESPinstallations.

Table 21 shows some downhole hydraulic pump lives for acollection of fields. The conditions for these fields are

presented in Reference 6 as well. The average life of thepumps is about 114 days. Target, downside and industry data

is summarized in Figure 20 for the downhole hydraulicpumps. Table 22 summarizes costs for operating withHydraulics in the study of Reference 6 for a 1000 bpd rate.These type of costs would have to be gathered for a number of

rates and conditions for the data to be available for generalapplication to an artificial lift study.

No data is presented for gas lift system costs and failuresexpected. Initial compressor costs are high but afterinstallation, most of the expenses are wireline work and new

or repaired valves, unless a major compressor fix or additionis needed. Cost examples for other systems are not shown

here.The data that is shown is, again, for particular fields and

may/may not be indicative of what you would expect for astudy that might be undertaken with other conditions present.

ConclusionsDiscussion has been presented on various methods available

for the selection of the best artificial lift system for givenconditions. The discussion reviews methods from a depth-ratefeasibility map, tables of advantages and disadvantages,

through expert system programs containing feasibilitytechnical, and economic programs.

Examples are given for calculating the net present value of

artificial lift methods as one example of how to economicallyselect the best method of lift. The examples show what data isneeded to allow the engineer to be able to make a choice thashould maximize profits over the life or a portion of the life of

the field. The examples presented assume that the user of theNPV method has used previously mentioned methods oreviewing advantages and disadvantages, and other feasibilitymethods to be sure that the systems economically analyzedcan be used for given conditions.

Since the NPV method reviewed requires designs to meettarget rates, then the user is somewhat forced to evaluate harshconditions, etc., during the course of the design. He has tothen add gas separators, sand trim, or whatever is necessary to

try to meet target rates before the NPV analysis is performedso by necessity, various feasibility criteria has to beconsidered. If target rates are not possible, then the system iseliminated from consideration.

The reader is left with a menu of various possibilities forselection of a lift method varying from use of simple chartsand tables, to economic analysis calculations, to use ofexisting or future expert system computer programs.

References1. Clegg, J.D., Bucaram, S.M. and Hein, N.W., New

Recommendations and Comparisons for Artificial Lift Method

Selection, SPE 24834; and Journal of Petroleum Technology

1128, December 1993.

2. Brown, K.E., Overview of Artificial Lift Systems, Journal ofPetroleum Technology, 2384, October 1982.

3. Panel Discussion, Neely, B. Moderator, Selection of ArtificiaLift Method, SPE 10337.

4. Espin, D.A., Gasbarri, S. and Chacin, J.E., Expert System forSelection of Optimum Artificial Lift Method, SPE 26967.

5. Heinze, L.R., Thornsberry, K. and Wit, L.D., AL: An ExperSystem for Selecting the Optimal Pumping Method, SPE 18872.

6. Valentin, E.P. and Hoffman, F.C., OPUS: An Expert Advisor forArtificial Lift, SPE 18184.

7. Etherton, J.H. and Thornton, P., A Case Study of the SelectionProcedure for Artificial Lift in a High Capacity Reservoir, SW

Petroleum Short Course 88.

8. Smith, G.L., Lease Operational Study Gas Lift vs. SubmersiblePump Lift G.H. Arledge C Lease, Scurry County, Texas

SPE 6852.9. Kol, H. and Lea, J.F., Selection of the Most Effective Artificia

List System for the Priobskoye Field, SPE ESP Workshop, Apri

26-28, Houston, TX.

10.Clegg, J.D., Artificial Lift Efficiency Depends on Design, TheAmerican Oil & Gas Reporter, 48, June 1991.

11.Lea, J.F., Artificial LiftOperating at Lower Cost, SPEDistinguished Lecturer Presentation.

12.Clegg, J.D., Artificial Lift: Producing at High Rates, SPEDistinguished Lecturer Presentation.

13.Johnson, L.D., Selection of Artificial Lift for a Permian BasinWaterflood, SW Petroleum Short Course, Lubbock, 1968.

14.Bennett, P., Artificial Lift Concepts and Timing, PetroleumEngineer, 144, May 1980.


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15.Weighhill, G.T., ESP Selection and Operating Strategy at WytchFarm.

16.Powers, M.L., The Depth Constraint of Electric SubmersiblePumps, SPE 24835.

17.Toolkit of computer programs by Integrity Consulting, Parker,CO.

18.Lea, J.F., Patterson, J., Selection Considerations for ArtificialLift, Artificial Lift Equipment Forum, Dubai, 1997.

AppendixThe economic equations used for the selection of lift methods

by economic analysis are summarized in this Appendix. Theequations are presented as pseudo code for readability. Valuesnot explicitly calculated are assumed to be user input values.

Initial Oil Rate (BBL/YR) = 365.25 x Initial

Production Rate xInitial Water Cut

Abandonment Oil Rate = 365.25 x TotalAbandonment Ratex Abandonment

Water Cut

Rdecl = Oil ProductionDecline Rate/100

Years to Abandonment = - (Ln(Initial Oil

Rate) Ln(Aband.Oil Rate))/Ln(1 Rdecl)

Initialize at Year 0

BOPD(0) = Initial Oil Rate / 365.25Water Cut(0) = Initial Water Cut

GOR(0) = Initial GORCumulative NPV (0) = 0Cumulative Oil (0) = 0

Calculate production decline factor

R = Ln(1 Rdecl)

Begin loop to calculate costs and present value up to the

abandonment year.

FOR YEARS I = 1 TO YEARS TO ABANDONMENTCalculate daily production rate at end of year 1

BOPD (I) = BOPD(0) x Exp(R* I)Calculate maximum production for year I for full

productionQmax (I) = 365.25 * (BOPD (I)

BOPD (I - 1)) / R

Adjust for lost productionQoil (I) = Qmax (I) - (Qmax (I) /

365.25) xDays/Workover x

Workovers/YearCalculate cumulative oil produced to end of year I

Cumulative Oil (I) = Cumulative Oil (I-1) +Qoil (I)

Straight line GOR and Water Cut

WC (I) = WC (0) + I x(Abandonment WC -Initial WC)/ Years to

AbandonmentGOR (I) = GOR (0) + I x

(Abandonment GOR -Initial GOR)/ Years to

AbandonmentCalculate Water and Gas Rates for Year I

Qwat (I) = Qoil (I) x WC (I) / (1 WC (I))Qgas (I) = .001 x Qoil (I) x GOR (I)

Calculate Required Cost and Revenue Factors

Rinflation = (1 + Inflation Rate / 100) ^(I - 0.5)

Rdiscount = (1 + Discount Rate / 100)^ (I - 0.5)

Roil = (1 + Oil Price Increase

Rate/ 100) ^ (I - 0.5)Requip = (1 + Equipment Cost

Increase Rate / 100) ^ (I -

0.5)Relec = Electricity cost / bbl

liquid produced = 24 xkW/blpd x $/kW

Calculate Fluid CostsFluid Cost (I) = Rinflation x Fluid

Disposal Cost/BBL x(Qoil (I) + Qwat (I) )

Calculated Fixed Operating CostFixed Cost (I) = Rinflation x 12 x

(Common Fixed Cost +Method Specific FixedCost)

Calculate Workover CostWorkover Cost (I) = Rinflation x

Cost/Workover Day xDays/Workover xWorkovers/Year

Calculate Equipment Cost. Equipment costs are specifiedfor each lift method and vary from method to method. Foreach method, the type of equipment (pump, sucker rods

tubing, ESP cable, etc), replacement cost for each type and theanticipated frequency of replacement (either as a run life tableor a fixed replacement interval) are specified.

Total equipment cost is calculated by summing over al

identified method specific equipment, including the equipmencost ONLY during those years where replacement isscheduled from the run life table or specified fixedreplacement interval.

Equipment Cost (I) = Equipment Cost (I-1)

FOR J = 1 to Number ofEquipment Types

IF year I is a replacement year for Equipment (J) THEN


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Equipment Cost (I) = Equipment Cost (I) +Requip x Cost ofEquipment (J)

ENDIF

END FORCalculate Electricity Cost

Electricity Cost (I) = Rinflation x Relec x

(Qoil (I) + Qwat (I))Calculate Total Costs for Year 1

Yearly Cost (I) = Fluid Cost (I) + FixedCost (I) + WorkoverCost (I) + Equipment Cost(I) + Electricity Cost (I)

Calculate Total Income for Year IYearly Income (I) = Roil x (1 Royalty/100)

x (Qoil (I) x $/BBl Oil+ Qgas (I) x $/Mscf)

Calculate Net Present Value from Year INet PV (I) = (Yearly Income (I) -

Yearly Cost (I)) /

RdiscountCalculate Cumulative Net PV from Year 0 to Year I

Cumulative NPV (I) = Cumulative NPV (I-1) +Net PV (I)

END FOR


14/30


Table 1: Relative Advantages of Artificial Lif t Systems(After K. E. Brown, JPT, Oct., 1982)

Rod Pumping

HydraulicPiston

Pumping

ElectricSubmersible

Pumping Gas LiftHydraulicJet Pump Plunger lift

ProgressiveCavityPumps

Relatively simplesystem design

Units easilychanged to otherwells withminimum cost

Efficient, simpleand easy for fieldpeople to operate.

Applicable to slimholes and multiplecompletions.

Can pump a welldown to very lowpressure (depth

and ratedependent).

System usually isnaturally ventedfor gas separationand fluid levelsoundings.

Flexible-canmatchdisplacement rateto well capabilityas well declines.

Analyzable.

Can lift high-temperature and

viscous oils.

Can use gas orelectricity aspower source.

Corrosion andscale treatmentseasy to perform.

Applicable topump off control ifelectrified.

Availability ofdifferent sizes.

Hollow suckerrods are availablefor slim holecompletions andease of inhibitortreatment.

Have pumps withdouble valvingthat pump on bothupstroke anddownstroke.

Not so depthlimited-can liftlarge volumesfrom great depths

500 B/D (79.49 m3/d) from 15,000ft. (4572 m) havebeen installed to18,000 ft.(5486.4 m)

Crooked holespresent minimalproblems.

Unobtrusive inurban locations.

Power source canbe remotelylocated.

Analyzable.

Flexible-canusually matchdisplacement towells capability aswell declines.

Can use gas orelectricity aspower source.

Downhole pumpscan be circulatedout in free

systems.

Can pump a welldown to fairly lowpressure.

Applicable tomultiplecompletions.

Applicableoffshore.

Closed system willcombat corrosion.

Easy to pump incycles by timeclock.

Adjustable gearbox for Triplexoffers moreflexibility.Mixing power fluidwith waxy orviscous crudescan reduceviscosity.

Can liftextremely highvolumes,20,000 B/D(19078 m 3/d),in shallow wellswith largecasing.

Currently lifting 120,000 B/D(19068 m 3/d)from watersupply wells inMiddle Eastwith 600-hp(448-kW) units;720-hp (537-kW) available,

1,000-hp (746-kW) underdevelopment.

Unobtrusive inurban locations.

Simple tooperate.

Easy to installdownholepressuresensor fortelemeteringpressure tosurface viacable.

Crooked holepresent noproblem.

Applicableoffshore.

Corrosion andscale treatmenteasy toperform.

Availability indifferent size.

Lifting cost forhigh volumesgenerally verylow.

Can handlelarge volume ofsolids withminorproblems.

Handles largevolume in high-Pl wells(continuouslift). 50,000B/D (7949.37m 3/d).

Fairly flexible-convertiblefromcontinuous tointermittent to

chamber orplunger lift aswell declines.

Unobtrusive inurbanlocations.

Power sourcecan beremotelylocated.

Easy to obtaindownholepressures andgradients.

Lifting gassy

wells is noproblem.

Sometimesserviceablewith wirelineunit.

Crooked holespresent noproblem.

Corrosion isnot usually asadverse.

Applicableoffshore.

Retrievable withoutpulling tubing.

Has no moving parts.

No problems indeviated or crookedholes.

Unobtrusive in urbanlocations.

Applicable offshore.

Can use water as apower source.

Power fluid does nothave to be so clean

as for hydraulic pistonpumping.

Corrosion scaleemulsion treatmenteasy to perform.

Power source can beremotely located andcan handle highvolumes to30,000 B/D (4769.62m 3/d).

Retrievable withoutpulling tubing.

Very inexpensiveinstallation.

Automaticallykeeps tubing cleanof paraffin, scale.

Applicable for highgas oil ratio wells.

Can be used inconjunction withintermittent gas lift.

Can be used tounload liquid from

gas wells.

Some typesare retrievablewith rods

Moderate Cost

Low Profile

Can usedownholeelectric motorsthat handlesand andviscous fluidwell

High electricalefficiency


15/30


Table 2: Relative Disadvantages of Ar tific ial Lif t Systems

RodPumping

HydraulicPiston

Pumping

ElectricSubmersible

Pumping Gas LiftHydraulicJet Pump Plunger Lift

ProgressiveCavityPumps

Crookedholes presenta friction

problem.

High solidsproduction istroublesome.

Gassy wellsusually lowervolumetricefficiency.

Is depthlimited,primarily dueto rodcapability.

Obtrusive inurban

locations.

Heavy andbulky inoffshoreoperations.

Susceptible toparaffinproblems.

Tubing cannotbe internallycoated forcorrosion.

H2S limitsdepth atwhich a large

volume pumpcan be set.

Limitation ofdownholepump designin smalldiametercasing.

Power oilsystems are afire hazard.

Large oilinventoryrequired inpower oilsystem whichdetracts fromprofitability.

High solidsproduction istroublesome.

Operating costsare sometimeshigher.

Usuallysusceptible to

gasinterference-usually notvented.

Ventedinstallations aremore expensivebecause ofextra tubingrequired.

Treating forscale belowpacker isdifficult.

Not easy forfield personnel

to troubleshoot.

Difficult toobtain valid welltests in lowvolume wells.

Requires twostrings of tubingfor someinstallations.

Problems intreating powerwater whereused.

Safety problemfor high surfacepressure poweroil.

Lost of poweroil in surfaceequipmentfailure.

Not applicable tomultiple compilations.

Only applicable withelectric power.

High voltages (1,000V) are necessary.

Impractical in shallow,low-volume wells.

Expensive to changeequipment to matchdeclining wellcapability.

Cable causesproblems in handlingtubulars.

Cables deteriorate in

high temperatures.

System is depthlimited, 10,000 ft.(3048.0 m), due tocable cost and inabilityto install enoughpower downhole(depends on casingsize).

Gas and solidsproduction aretroublesome.

Not easily analyzableunless goodengineering know-how.

Lack of productionrate flexibility.

Casing size limitation.

Cannot be set belowfluid entry without ashroud to route fluidby the motor. Shroudalso allows corrosioninhibitor to protectoutside of motor.

More downtime whenproblems areencountered due toentire unit beingdownhole.

Lift gas is not alwaysavailable.

Not efficient in liftingsmall fields or onewell leases.

Difficult to liftemulsions andviscous crudes.

Not efficient for smallfields or one-wellleases if compressionequipment is required.

Gas freezing andhydrate problems.

Problems with dirtysurface lines.

Some difficulty inanalyzing properlywithout engineeringsupervision.

Cannot effectivelyproduce deep wells toabandonment.

Requires makeup gasin rotative systems.

Casing mustwithstand liftpressure.

Safety problem withhigh pressure gas.

Relativelyinefficient liftmethod.

Requires at least20%submergence toapproach best liftefficiency.

Design of systemis more complex.

Pump maycavitate undercertainconditions.

Very sensitive toany change inback pressure.

The producing offree gas throughthe pump causesreduction in abilityto handle liquids.

Power oilsystems are firehazard.

High surfacepower fluidpressures arerequired.

May not takewell todepletion;

hence,eventuallyrequiringanother liftmethod.

Good for low-rate wells onlynormally lessthan 200 B/D(31.8 m/d).

Requires moreengineeringsupervision toadjust properly.

Danger existsin plunger

reaching toohigh a velocityand causingsurfacedamage.

Communicationbetween tubingand casingrequired forgood operationunless used inconjunction withgas lift.

Elastomers instator swell insome well fluids

POC is difficult

Lose efficiencywith depth

Rotating rodswear tubing;windup andafter-spin ofrods increasewith depth


16/30


Table 3: Capacities of Reciprocating Hydraulic PumpsTubingSize

Working FluidLevel, ft.

Maximum PumpDisplacement, B/D

2-3/8" 6000 to 17000 1311 to 3812-7/8" 6000 to 17000 2500 to 7443-1/2" 6000 to 15000 4015 to 1357

Table 4: Capacities of jet free pumpsTubing Production B/D2-3/8" 30002-7/8" 60003-1/2" 10000

Table 5: Lift Methods Costs: Low Rate CaseBeam Hydraulic Gas Lift ESP

Target Rate (bbl/day) 1000 1000 1000 1000Initial Installation ($) 141000 173000 239000 105000Energy Efficiency (%) 58 16 15 48Intake Pressure (psia) 900 900 900 900

Lift Energy (kw/bbl/day) .025 .096 .100 .031Workover Cost ($/day) 1000 1000 1000 1000Wireline Cost ($/day) - - 1000 -Injection Gas ($/Mscf) - - .24 -Other Costs($/month) 200

(Maintenance)2900

(Maintenance)600

(CompressorMaintenance)

225(Inventory)

Table 6: Beam Pump Equipment Costs, Low Rate CaseItem Cost ($) Life (yrs)Tubing 80000 15Rods 20000 4Pump 6000 Run Life Table

Table 7: ESP Equipment Costs, Low Rate CaseItem Cost ($) Life (yrs)Tubing 80000 15Pump 25000 Run Life TableProtector 4000 Run Life TableSeparator 5000 Run Life TableMotor 15000 *Run Life TableCable 50000 6Cable Protector 20000 15Transformer 12000 15VSD 35000 15

Motor life assumed 2 x pump life

Table 8: Gas Lift Equipment Costs, Low Rate CaseItem Cost ($) Life (yrs) ReplaceTubing 80000 15 -Valve 2000 3 2Mandrel 5000 10 6


17/30


Table 9: Hydraulic Pump Equipment Costs, Low Rate CaseItem Cost ($) Life (yrs)Tubing 80000 15Pump 20000 Run Life Table

Table 10: System Run Li fe Data

Year

Beam Pump

(days)

ESP Pump

(days)

Hyd. Pump

(days)

Inj. Gas Volume

(Mscf/d)1 300 200 300 6002 400 7003 600 8004 750 9005 1000

Table 11: Summary of Low Rate NPV Calculations - Constant RateMethod NPV (MM$) Costs (MM$) Cost/NPVESP 4.7 .82 .17Gas Lift 3.80 .82 .22Hydraulic Pump 4.28 1.12 .26Rod Pump 4.70 .67 .142

Table 12: Equipment Operational Costs, High Rate CaseJet Gas Lift ESP

Target Rate (bbl/day) 17000 17460 17020Initial Installation ($) 200000 265000 150000Energy Efficiency (%) 21 16 41Lift Energy (kw/bbl/day) .042 .056 .022Workover Cost ($/day) 2000 2000 2000Wireline Cost ($/day) - 2000 -Injection Gas ($/Mscf) - .24 -Other Costs($/month) 2900

(Maintenance)3000

(CompressorMaintenance)

225(Inventory)

Table 13: ESP Equipment Costs, High Rate CaseItem Cost ($) Life (yrs)

Tubing 80000 15Pump 25000 Run Life TableProtector 4000 Run Life TableSeparator 5000 Run Life TableMotor 15000 *Run Life TableCable 50000 6Cable Protector 20000 15Transformer 12000 15VSD 35000 15

* Motor life assumed 2 x pump life

Table 14: Gas Lift Equipment Costs, High Rate CaseItem Cost ($) Life (yrs) Replace

Tubing 80000 15 -Valve 2000 3 2Mandrel 5000 10 6


18/30


Table 15: Hydraulic Pump Equipment Costs, High Rate CaseItem Cost ($) Life (yrs)Tubing 80000 15Pump 20000 Run Life Table

Table 16: System Run Lives, High Rate Case

Year

Beam Pump

(days)

ESP Pump

(days)

Hyd. Pump

(days)

Inj. Gas Volume

(Mscf/d)1 300 200 300 3002 4003 6004 750

Table 17: Summary of NPV Analysis, High Rate CaseMethod NPV (MM$) Costs (MM$) Cost/NPVESP 218.2 3.4 .016Gas Lift 211.1 4.0 .019Jet Pump 222.9 4.4 .020

Table 18: Field conditions for THUMS field where MTBFs are illustrated in Figure 18

Zone Ranger Terminal UP FordOn/Offshore Offshore Offshore OffshoreActive Producers 439 128 44General Description Unconsolidated Poorly Moderately

Sandstone Consolidated ConsolidatedSandstone Sandstone

W ell Production, BFPD 200 - 5,500 120 - 3,500 40 - 1,500Pump IntakePressure, psi 100 - 850 100 - 850 100 - 600Vertical Depth, ft 2,100-3,200 2,800 - 4,200 4,100 - 7,100Oil Gravity, oAPI 15 20 28GLR, scf/bbl 11 35 80

Avg. Resv. Press., psi 1,000 1,100 1,400Avg. Temp. oF 130 160 210Avg. Water Cut, (%) 94 82.5 80Avg. Viscosity, cp 80 15 5Scale CaCO, BaSO4 CaCO, BaSO4 CaCO

light - heavy light - heavy light - heavyAbrasives 0-5% 0-5% 0-1%CO2, ppm, 0-4000 0-4000 0-2000H2S, ppm 0-4000 0-4000 0-2000Emulsion Problems Y Y YCasing Size 8-5/8", 32# 8-5/8", 32# 9-5/8", 40#Liner Size 6-5/8", 28# 6-5/8", 28# 7", 26#Completion Gravel Pack Gravel Pack Slotted Liner

Tubing Size 2-7/8", 6.4# 2-7/8", 6.4# 2-7/8", 6.4#


19/30


Table 19: Summary of lives and costs of various components of an ESP system (Ref. 6)

900 BPD TARGETCASE equipment: 389 stag e pump 120 HP mot or No 2 cab le

it em / ye arly c o stPV c ost 1 2 3 4 5 6 7 8 9 10 11 12

Workover frequency 2.8 1.1 0.6 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5

investment:

pump / protec tor 24.3 68.5 26.5 14.6 12.1 12.1 12.1 12.1 12.1 12.1 12.1 12.1 12.1 separator 3.9 11.1 4.3 2.4 2.0 c ab le 50.3 50.3 50.3 motor 20.4 28.7 11.1 6.1 5.1 5.1 5.1 5.1 5.1 5.1 5.1 5.1 5.1 downhole sensor 5.6 15.8 5.6 5.6 5.6 tub ing 83.0 83.0 step-up transformer 10.2 10.2 VSD/ switc h boa rd 31.2 31.2 c ab le protec tors 14.0 14.0

operating c osts: e lec tric ity 20.4 20.6 20.9 21.1 21.4 21.6 21.9 22.1 22.4 22.7 22.9 23.2 workover 15.0 42.3 16.4 9.0 7.5 7.5 7.5 7.5 7.5 7.5 7.5 7.5 7.5 inventory 2.7 2.7 2.7 2.7 2.7 2.7 2.7 2.7 2.7 2.7 2.7 2.7 overhead 22.7 5.2 3.7 3.4 2.9 2.9 6.0 3.0 3.0 3.0 3.0 3.0TOTAL ESC. EXPENSE 400.8 96.0 70.2 66.9 60.5 63.3 133.7 69.2 72.3 75.6 79.1 82.7

cashflow (977) 257.9 -401 -96 -70 -67 -61 -63 -134 -69 -72 -76 -79 -83

all c ost x $1000

Table 20: Summary of some lives of ESP equipment derived for the study in Reference 6.

Estimated cumulative service life for ESP components .

Component/case150 BFPB

target300 BFPD

target>450 BFPD

target150 BFPDdownside

300 BFPDdownside

>450 BFPDdownside

Pump/intake target curve target curve target curve 500 curveSeparator target curve target curve target curve 500 curveMotor 2x target 2x target 2x target 2x 500Cable 6 years 6 years 6 years 6 years 6 years 6 yearsd.h. sensor target curve target curve target curve 500 curve

Transformer 15 years 15 years 15 years 15 years 15 years 15 yearsVSD 5 year 5 year 5 year 5 year 5 year 5 yearTubing 15 years 15 years 15 years 15 years 15 years 15 years1Cumulative service life in this table is related to the estimated run life depicted in Figure 19.2Rotary separators will be used for the first 5 years only3VSDs will only be used for the first 5 years.


20/30


Table 21: Summary of hydraulic pump l ives for various fields.

RUN LIFE DATA FOR HYDRAULICSJFL / TRC

Operator Depth Production Power System Pump Run Life Comments

(ft) (bpd) (days)

Citronell Unit 10-11000 300-400 Triplex, oil system 49 Use Kevlar spring loaded plungers & liners

Operator, 3000 psi injN. Of Mobile, Al. Several wells on

one pump

Texaco 15,000 100-450 Triplex, oil system 75 Like soft pack TriplexBarre Field, 1800-2400 bpd oil

S. Al. at 3900 psi

Unocal 10,500 15-50 Triplex, oil 165 Single string systemsWyoming Vortex to clean oil Pressure annulus to bring pump up

Woodland Unit Takes about 1000 psi to move pmp up

MWJ 10,000 75 Triplex, 3000-3500 90 Recip pumps, corrosion treat BHA'sBaum/Sanders psi 1 inch vent string

in New Mexico no trouble Production up casing

J. Schlagel Injection down tubing (2 3/8)

Recommends individual pwr supplyMarathon 7,500 475 Triplex,uses 180 (min) Slower pumps (lt. 45 spm) mayCody Unit, WY water and oil run 3 years..

Andy Franklin for pwr fluid Pump repair: $1500-2000

(likes now with Vortex cleanup For frac cleanup the fill

experience) 4 spd trans well with liquids, circulate and filter with

vortex unit at surface

Single string- monitor tub press for

pump off..trying VSD

200-300 psi on casing brings up pmp

UNOCAL 4,000 295 1st Triplex with oil Use 3 string, main& 2 side stringsHuntington Beach now ESP with

waterFree pump installations

Joe Gonzales some 3000 psi Power water not mixed with production

some 2000 psi BHA's 3 years

side strings leak, pull only one string if side string

few hrs to pull side string

4 hrs to round trip new pump

ESP's less maintenance, more energy to run

Triplex's more maintenance, less energy to run

Cook Inlet 7,500 105 avg Triplex & ESP 180 plus Use recip and jet pumpsUNICAL Oil system 2 1/2 hrs to replace pumps

Dean Geisert tank onlyseparation

Tubing tripped not more than 3-4 years

likes hydraulicbetter

no vortex cleanup two strings, open annulus

than ESP's 3550 psi

generated

check fluid level with echometer

60 hz esps runs two strings simultanously

gears on triplex's

Average Pump Run Li fe, days

114.5


21/30


Table 22: Summary of run li ves and costs assumed fo r one rate for study of Reference 6.

1 0 0 0 B P D T A R G E T C A S E H y d r a u lic P u m p S y s t e m s

it e m /ye a r ly c o s t

P V c o s t 1 2 3 4 5 6 7 8 9 1 0 1 1 1 2

p u m p re p a ir f r e q . 2 .0 0 2 .0 0 2 .0 0 2 .0 0 2 .0 0 2 .0 0 2 .0 0 2 .0 0 2 .0 0 2 .0 0 2 .0 0 2 .0 0

i n v e s t m e n t : d o w n h o le p u m p 1 0 .0 1 0 .0 1 0 .0

a s s o c ia t e d e q u ip m e n t 3 0 .0 3 0 .0 1 0 .0

p o w e r f lu id p u m p * 5 0 .0 5 0 .0 5 0 .0

p o w e r f lu id s y s t e m 1 1 0 .0 1 1 0 .0

a u t o m a t io n e q u ip m e n t 1 0 .0 1 0 .0

t u b in g 1 5 5 .4 1 5 5 .4

o p e r a t in g c o s t s : e le c t r ic it y 3 8 .4 3 8 .8 3 9 .3 3 9 .8 4 0 .2 4 0 .7 4 1 .2 4 1 .7 4 2 .2 4 2 .7 4 3 .2 4 3 .7

w o rk o ve r 3 0 .0 6 0 .0 3 0 .0

w e ll a t t e n d e n c e 2 .5 2 .5 2 .5 2 .5 2 .5 2 .5 2 .5 2 .5 2 .5 2 .5 2 .5 2 .5

s u r f a c e e q p m . m a in t . 1 1 .2 1 1 .2 1 1 .2 1 1 .2 1 1 .2 1 1 .2 1 1 .2 1 1 .2 1 1 .2 1 1 .2 1 1 .2 1 1 .2

d o w n h o le p u m p re p a ir * 4 .0 8 .0 8 .0 8 .0 8 .0 8 .0 8 .0 8 .0 8 .0 8 .0 8 .0 8 .0 8 .0

o ve rh e a d 2 9 .1 3 .6 3 .7 3 .7 3 .7 3 .7 9 .8 3 .8 3 .8 3 .9 3 .9 3 .9

T O T A L E S C . E X P E N S E 5 1 4 .6 6 6 .7 6 9 .9 7 3 .3 7 6 .8 8 0 .5 2 1 8 .5 8 8 .5 9 2 .7 9 7 .2 1 0 1 .9 1 0 6 .8

c a s h f l o w (1,222) 3 9 9 .4 -5 1 5 -6 7 -7 0 -7 3 -7 7 -8 1 -2 1 9 -8 8 -9 3 -9 7 -1 0 2 -1 0 7

a l l c o s t x $ 1 0 0 0

0 100 200 300 400 500 6000

500

1000

1500

2000

Liquid Rate, Bbl/D

Pressure,psig

Inflow @ Sandface (1) Not Used

Inflow (1) Outflow (A)

Not Used Not Used

Not Used Not Used

Not Used Not Used

Not Used Not Used

Not Used Not Used

Not Used

11

Reg: James F. Lea - Amoco

Figure 1: IPR with bubb le point below static reservoir pressure.

Figure 2: Schmetic of geometry of horizontal well inflow model.


22/30


0 100 200 300 400 500 6000

500

1000

1500

2000

Liquid Rate, Bbl/D

Pressure,psig

Inflow @ Sandface (1) Not Used

Inflow (1) Outflow (A)

Case 2 (2) Case 2 (B)

Case 3 (3) Case 3 (C)

Case 4 (4) Case 4 (D)

Case 5 (5) Case 5 (E)

Not Used Not Used

Not Used

112345

Inflow

Inflow

Declining reservoir press, psia

(1) 2000.0(2) 1800.0(3) 1600.0(4) 1400.0(5) 1200.0

Reg: James F. Lea - Amoco Figure 3: IPRs decreasing wi th time.

Figure 4: Major Artif icial Lif t Systems (from Trico)


23/30


A r t i f i c i a l L i f t : R a t e v s . D e p t h v s . M e t h o d

0

2000

4000

6000

8000

10000

12000

14000

16000

18000

1 10 100 1000 10000 100000

DEPTH,

FT

Hyd. Jet

Hyd.

Recip.

0

2000

4000

6000

8000

10000

12000

14000

16000

18000

1 10 100 1000 10000 100000

BPD

DEPTH,

FT

Ref: Pennwell AI Methods

Chart, 1986

Plunger

Gaslift

Beam

ESP

PCP

Figure 5: Depth/Rate Selection Chart after Blais


24/30


Figure 6: Schematic of Beam Pumping System

Figure 7: Schematic of Typical ESP system


25/30


Figure 8: Schematic of PC pump.

The ESPCP SystemThe ESPCP System

Progressing cavity pump driven

by submersible motor

Replaces Rod-Driven PC Pump

Units:

Deviated wells

Viscous production

Flex Shaft

Assembly

Gear

Reducer

Electric Motor

PCP

Seal SectionCable

Figure 9: Schematic o f ESPPC system


26/30


The ESPCP SystemThe ESPCP System

Standard components include:

Seal section

Motor

Cable

PC pump

New components include:

Intak

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