With 80 percent of the oil produced today coming from fields developedbefore 1973, artificial lift systems are playing a significant role in the

modern oil and gas industry. To help maximize production from these reservoirs,customers can choose from five artificial lift systems with distinct capabilities:

ROD LIFT, PROGRESSING CAVITY PUMPING, GAS LIFT,HYDRAULIC LIFT OR ELECTRIC SUBMERSIBLE PUMPING.

ArtificialLift.

Are you considering all the options?

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The difficult aspect is choosing the bestsystem for maximum performance, sincethe proper selection requires a thoroughunderstanding of the types of lift and specific reservoir conditions, including:well depth, volume of fluid to be pumpedand the properties of those fluids, theamount of gas produced, the pressure inthe reservoir and the presence of sand.Other factors such as cost constraints and equipment capabilities also must be considered.

To eliminate some of the guesswork,Weatherford uses a five point systematicsolution process that includes:

Data collection/confirmation

Elimination process (ruling out systems that do not meet that wellsparticular criteria)

Systems analysis (which system trulyis the best for that application)

Final selection (economic evaluation,which equipment is available for thecustomers timeframe)

Follow-up analysis (did the systemmeet expectations?)

We often find that operators repeated-ly use the same artificial lift system, regardless of the uniqueness of the reservoir, because they are comfortablewith the familiar, said Lee Colley,President of Weatherfords Artificial Lift

division. As the industrys only companythat provides a complete suite of artificiallift systems, products and services, our goal is to help customers analyzewhich system is the best for maximizingtheir production and ultimate reservoirrecovery.

Consider the following scenario:What would be the best artificial lift system to use in a low gas/oil situationwhen operating at 10,800-foot depth with a 7-inch casing, 27/8-inch tubing, with a bottomhole temperature of 260 degrees F, a bottomhole pressure of1,700 pounds per square inch (psi), and a wellbore deviation of 22 degrees with adog-leg and a required production rate of 600 BFD?

A) Reciprocating Rod LiftB) Electric Submersible Pumping (ESP) C) Hydraulic Lift D) Gas Lift

Based on the conditions mentioned, the reservoir is deep and wellbore iscrooked, making it an ideal hydraulic liftcandidate. Reciprocating rod lift is not the optimum choice because of the failure rateof rods and pumps in this environment.ESPs are not a good choice due to the temperature, depth, reservoir pressure andhigh gas/oil ratio.

Read on for further details.

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100806040200

US Canada FSU International

Aging Fields/Increasing Decline Rates

PERCENTAGE OF WELLS ON ARTIFICIAL LIFT

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Representing more than 80 percent of all systems in use worldwide, reciprocating rod liftpumping systems dominate the market for artificial lift equipment. These systems are primarily used to recover light and heavy oilfrom land wells, since the weight, footprint,wellbore angle and well servicing costs make itundesirable for most offshore platform locations.

The most common form of artificial lift is thetraditional beam pump system because of itslong history, reliability and ability to reuse components in different well applications. Thissystem includes a beam-pumping unit andsucker rods attached to a downhole pump.Powered by either gas or electricity, the reciprocating rod lift system has the flexibility to adjust production through stroke length,pump size and speed.

For example, although rod lift systems aremost effective in low-to-medium volume applications the typical range is between 20-1,000 barrels per day (b/d) some operatorshave achieved higher lift volume requirementsby utilizing long-stroke pumping units(RotaflexTM). Likewise, in troublesome and high-volume wells, a type of long slow strokepumping system is frequently used to extendtubing wear and eliminate gas lock problems.

The advantages of reciprocating rod liftinclude high system efficiency, upgraded materialsthat reduce corrosion, repairs that can be con-ducted while the well is in service, and a highsalvage value for surface and downhole equip-ment. The systems primary limitation is depth,due to rod capability. Other considerationsinclude tubing and rod wear and gas-oil ratios.

Sucker Rod

Tubing AnchorCatcher

Sucker RodPump Assembly

RECIPROCATING

SYSTEMSRod Lift

ROD LIFTSYSTEM

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USE ROD LIFT FOR: Recovering light or heavy oil Typical operating depth range is

2,000 feet-11,000 feet; in certain conditions can reach 16,000 feet

Typical operating volume is 20 to1,000 b/d; in certain conditions canattain 3,500 b/d

Typical operating temperature is 100 - 250F; the maximum temperature is 550F.

Rotaflex units 21

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Lowered lifting costs, improved fluid production and increased pump efficiency were three benefitsresulting from a major oil companys controlled test of a mechanical long-stroke pumping unit as a possible alternative to conventional pumpjacks in thermal applications.

The company had been using a conventionalbeam unit pumping system with a variablefrequency drive for speed control on a number ofmultilateral horizontal cyclic steam wells. Tooptimize its system, the company field-tested themechanical long-stroke pumping unit (WeatherfordsRotaflex system) for operating reliability, its abilityto lift available production, power consumption(lifting cost) and the frequency of maintenance.

The field test ran from mid-July 1998 through theend of November, and included a pump-off controllersystem on one long-stroke and one conventional beampumping unit, enabling close monitoring of wellconditions and differences in operating parameters.

Test data concluded that thermal applications couldapply a cost-effective pumping system using amechanical long-stroke pumping unit. Primary benefitsof the long-stroke units included improved fluidproduction (on average, the well test production rateon the Rotaflex wells was 41 percent higher.)

At the same time, the average pump efficiencyincreased from 46.8 percent to 67.6 percent, and liftingcosts were lowered by more than 18 percent.Additionally, inspection on the pumps after the firstproduction cycle showed that on average the wear inpumps from the Rotaflex wells was noticeably lessthan in the units from the other wells.

Colin Rae, Regional Sales Manager, Artificial Lift (left) andSteve McLeod, Area Manager North Sea pictured with some of the components of Weatherfords gas lift systems. Gas lift is the most common form of artificial lift used for North Sea reservoirs, followed by electric submersible pumping.

Gas lift most clearly resembles the naturalflow process and is the preferred form ofartificial lift when there is an economicalsupply of pressurized injection gas. Thesesystems are used on multiple and slim hole completions and can handle sandy conditions well.

With a low initial installation cost, gas liftsystems are ideally suited for offshore oilwells because they require less platformspace and centralized gas compression.These systems are also used to kick off wellsthat will flow naturally once the heaviercompletion fluids leave the productionstring. An efficient form of artificial lift, gaslift systems are used throughout the world in a variety of locations, including the Gulf ofMexico, Venezuela, Nigeria, Russia, Oman,and Brunei.

Gas lift systems include gas lift valves,mandrels and accessories, surface controls,packoff equipment, and coiled-tubing gas liftequipment. Advantages include good liftingefficiencies, minimal moving parts and flexibility in lifting from near the surface ordeep within the wellbore. Many gas lift

systems incorporate wireline retrievablevalves, which allows for increased liftingflexibility and low cost well servicing.

Considerations should be given to the following restrictions before using gas lift: it needs a high-pressure gas source and it isnot efficient in lifting small fields or singlewell leases.

Gas Lift

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USE GAS LIFT FOR: Working on offshore wells or on land

wells where a natural supply of gas is available

Typical operating depth is 8,000 feet; maximum is 15,000 feet

Typical operating volume is 400 b/d; maximum is 30,000 b/d

Typical operating temperature is 180F;maximum is 400F

Case history Rotaflex

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Over the past 20 years, use of ProgressingCavity Pumping (PCP) systems has grown substantially. Initially used to produce onlyhigh viscosity sand-laden heavy oil, PCPsalso are now a widely accepted artificial liftmethod for shallow high water cut, highvolume production and de-watering coalbed methane wells.

The growth and popularity of PCPs areexpected to continue, due to several factors.First, todays progressing cavity pumpingsystems offer a wider range of volume andlift capacities they can operate to depthsof up to 6,000 feet and have a maximum production rate of 4,000 b/d. Second, morepump choices exist to suit a broader rangeof producing environments. Third, severalnew pump materials have been developedfor more aggressive producing environ-ments.

Other developments include vastimprovements in the experience required to properly apply and service the pump systems, more comprehensive design programs for selecting PCP systems andspecifically developed databases that trackinstallations and document pump run life.

Key advantages to the PCP systeminclude low capital costs, power consumption and noise levels; low profilesurface equipment; high resistance to abrasion; high overall system efficiencies;simple installation, operation and maintenance (no internal valves to lock orstick); and capacity to pump a wide rangeof fluid viscosity, production rates andpressures.

For one major oil company, a gas lift solutionmeant cost savings of an estimated $86,000.Located in Lafayette, La., the customer had a horizontal low-pressure well that was operating at TVD 5,280 feet. The task was todetermine which artificial lift system wouldkick off the well after the completion.

The Weatherford solution consisted oftwo valves the Proportioning DifferentialValve (RPDV-1) and the Dump Kill Valve(RDDK-1) which allow the customer to testthe packer and then unload the well withoutintervention.

On the initial completion, four-sided mandrels were spaced out at 650-foot increments from top station kickoffdepth. The top three unloading stationswere equipped with RPDV-1 valves to closeat a differential of 320 psi. The bottom mandrel was loaded with an RDDV-1 valveset to shear at 2,000-psi differential.

After careful testing, the casing pressurewas increased to 1,950 psi. This step closed the RPDV-1 valves and sheared the RDDK-1

valve, causing circula-tion between the casingand the tubing. Onceequalized, the RPDV-1differential valvereopened, allowing thewell to be unloadedwith gas lift.

The rig was then moved off location and the wellwas completed. Thisprocess eliminatedwell re-entry, timeand associated risks.Upon its completion,the procedure savedthe customerapproximately$86,000: $40,000 inrig time; $6,000 inwireline chargesand $40,000 in theelimination ofnitrogen testing.

Side PocketMandrel withGas Lift Valve

Side PocketMandrel withGas Lift Valve

Side PocketMandrel withGas Lift Valve

CompletionFluid

SingleProductionPacker

Progressing Cavity

PUMPING SYSTEMS

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GAS LIFTSYSTEM

Case history Gas Lift ValveApplication

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Components of the PCP system includethe downhole pump, continuous or conventional sucker rod, a surface drive and various types of torque and/or speedlimiters. All system components should beconsidered to optimize each application.Well parameters that are evaluated witheach application include the volume of fluid and pressure required, bottom

hole temperature, producing fluid, aromatic content, levels of carbon dioxide or hydrogen sulfide, and the reservoirs past history.

With a mature PCP market share alreadya fact in Canada, growth is now occurringin areas such as the United States,Venezuela and Brazil, as well as in emergingmarkets in Indonesia and Argentina.

Casing

ProductionTubing

SuckerRod

Sucker RodCoupling

Tubing Collar Stator

Rotor

Tubing Collar

Tag Bar Sub

PCPSYSTEM

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USE PCP FOR: All well types, including horizontal, slant,

directional and vertical reservoirs Typical operating depth is 2,000 - 3,000 feet;

maximum is: 6,000 feet Typical operating volume is 50-2,000 b/d;

maximum is: 4,000 b/d Typical operating temperature is 75-110F;

maximum is 200F

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Electric submersible pumping systems (ESP) are typically targeted for high volume wells where gasis not readily available for use in gas lift. Becausethey require very little space on the platform andcan be installed in highly deviated wells, they areideally suited for offshore installations.

The U.S. (which has approximately 10,000 ESPsin service), Russia and Indonesia currently consti-tute the largest markets for ESPs. Major growthareas will include reservoirs that have lost pressureand have increasing water cut. The North Slope of Alaska and the former Soviet Union are goodexamples of areas that are using increasing numbers of ESP pumps.

ESP installations are considered harder todesign than other forms of artificial lift becausethey require an understanding of hydraulic,mechanical and electrical systems. Recentadvances in software programs, however, havehelped by rapidly examining design parametersand evaluating options. Furthermore, a properlydesigned ESP system providing that the correctequipment is selected requires little or no monitoring or daily maintenance and should havea bottom hole life in excess of three years.

Key elements of the ESP system include thepump, motor, protector, cable and controller.Submersible pump assemblies are located downhole, with only the control mechanism andtransformers above ground.

In addition to handling deviated wells, otheradvantages of the ESP system include high volume and depth capability (can reach a maximum depth of 12,000 feet and a maximumoperation volume of 30,000 b/d) and the ability

to adapt to a variety of wellbore configurations.At producing rates below 1,000 b/d, however, rodlift systems are normally more cost-effective than ESPs.

Considerations for ESPs include that the system can only be operated with electric powerand high voltages. Likewise, ESP systems do notwork well for gassy fluids. Modern gas separatorsavailable with ESP systems can remove a fairamount of free gas and allow the pump to operatesuccessfully, but for a high volume well with ahigh gas/oil ratio, gas lift may be a better option.

ProductionTubing

Pump

SealSection

Motor

PowerCable

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USE ESP FOR: Handling deviated wells and adapting to

all wells with 51/2 -inch casing and larger High volume and depth capability Typical operating depth range is

1,000-10,000 feet Typical operating volume range is

600-8,000 b/d Typical operating temperature range is

100-250F; maximum is 325F

ESPSYSTEM

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ElectricSubmersible

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Because of their ability to operate in high volume, highdepth requirements, hydrauliclift systems have been gainingpopularity during the past fiveyears. As of 1998, approximately1,750 wells worldwide wereusing hydraulic lift systems,with more than 1,100 operating

in North America. In the international arena, the tech-nology is being introducedinto new markets such asWest Africa and Mexico.

Hydraulic lift systems areused primarily for recoveringmedium to light oil. Systemcomponents include the surface power fluid andcleaning units, and subsurface jet or pistonhydraulic pumps. Thejet pumps, with nomoving parts,high alloy construction and abrasion resistant

components, provide long runtimes, even in sandy or highly corrosive well environments.Likewise, the piston hydraulicpumps can efficiently lift fromgreat depths, and have the potential to operate to almosttotal well depletion.

Both types of hydraulic pumps are commonly circulatedto the surface for maintenance, dramatically reducing welldown-time and eliminatingpulling unit expenses.Additionally, both jet and piston pumps operate very successfully in highly deviatedwellbores.

Produced well fluid is pressurized by the surfacepower unit and is used as thepower source to operate thedownhole pump. The surfacepower installation can be positioned at a central locationto serve multiple wells, or as aconvenient skid-mounted unitlocated at the individual wellsite. The system has theability to use gas or electricityas the power source.

Hydraulic lift systems areone of the most versatile

types of artificial lift.However, jet pumps

are limited by verylow bottom hole

pressure and piston

types by highgas-to-liquid

ratios.

USE HYDRAULIC LIFT FOR: Deep, deviated wells Typical operating depth: 10,000 feet

Piston can go to 17,000 feet; maximum for Jet is 20,000 feet

Typical operating volume of 500 b/d,but can go to 4,000 b/d (Piston); Jet is 1,000 BPD, with a maximum of approximately 15,000 b/d

Typical operating temperature forPiston and Jet is 100 - 250F, maximum of 500F

ProductionCasing

High PressurePower Fluid

Packer Nose

Bottom HoleAssembly

Piston or JetFree Pump

StandingValve

HydraulicLIFT

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Maximizing recovery benefits sometimes isas simple as taking advantage of a resourcethat has been underutilized, as demonstratedby an East Texas operator whose reservoirhas continued to flow oil without asignificant increase in operating costs.

From 1950 to 1970, the reservoir used rodpumps to supplement the reservoirs naturalenergy. With time, the wells depleted, production decreased and maintenance problems with rod and tubing wear becameapparent. To increase efficiency, operatorsbegan searching for an artificial lift system toincrease their total production and reducemaintenance costs, without increasing operating costs.

Based on the specific conditions of thereservoir and assistance from Weatherfordexperts, the operator selected a hydraulic lift system to supplement the wells naturalenergy. The system included a 60-horsepower(hp) Unidraulic and 2-inch downhole jetpump. A gas engine using produced gasfrom a reservoir was chosen to power theUnidraulic. An approximately 20 percentincrease in production resulted, with no realincrease in operating costs. In 1985, twoadditional 100-hp Unidraulic systems wereadded and the 60-hp unit was upgraded to100 hp. The total system included a 150-hpwater injection pump that was also poweredby the natural gas engine.

Today, the reservoir operates with basically the same equipment. It yieldsapproximately 2,300 b/d, costs about $0.014per barrel of fluid to be produced and 41cents to produce a barrel of oil, consideringonly maintenance and repair costs.

In 1999, Lee Colley noted, Weatherfordwill introduce new technologies that will pushthe operating envelope of current artificial liftmethods in both capability and improved system economics. These technology initiatives include subsurface pump develop-ments that will significantly improve the efficiency in volumetric sweep and extendoperating life. Also included are a number ofthru-tubing technologies to save the cost ofpulling tubing and reduce lost productionwhile servicing the well.

Colley also noted that other areas of focus include the continued expansion ofWeatherfords contract services, which installand manage artificial lift systems, partneringwith clients to develop specialized and uniqueartificial lift system configurations, and further development of well site optimizationpackages, which use well site informationgathering to enhance artificial lift performance.Weatherford also is exploring opportunities tocombine different types of technologies, suchas gas lift with PCPs, or using hydraulic lift todrive PCPs.

Weatherfords artificial lift goal is tocontinue to seek initiatives and solutionstrategies, which with other industryimprovements will position us as atechnology leader, said Colley.

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Case history UnidraulicSystem Future Plans

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