artificial lift dude

8/10/2019 artificial lift dude

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Production Engineering

Objectives


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Production Engineering Objectives

1. Design and set the parameters for operationof a well or a system of wells in a safe andoptimized way during the whole well life.

associated with the maximization of the profit orthe production, subject to some constraints.

Maximization o f the ult im ate pro f i t from an oi l

f ie ld is achieved by designing a safe cost

ef fect ive system that balances rate of

produ ct ion against costs of prod uct ion


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Objectives

New

Production

Wells

Maximize

ProfitOptimization

Design


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Production Engineering Objectives

2. Follow up the performance of wells that arealready in production in order to determine if

the system is behaving as expected. Make the appropriate recommendations in order

to safely bring the system to a new optimizedstate.


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Production

Wells

Performance

Deviations

Problem Detection and

Corrective Actions


Objectives

Maximize

Profit

Monitor Performance

Analyze

Design

Optimization


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ObjectivesIn order to accompl ish those

object ives the product ion engineer

mus t ful ly understand the nature of anoi l wel l and must master the

interact ion between al l other sub-

discipl ines

He must also ful ly understand thepo tential and l im itat ions o f art if ic ial l i f t

techniques


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The Producer Oil Well


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Oil Well

1. A production oil well is drilled to provide a

connection between the reservoir and the surface

facilities.

2. Its main purpose is to allow the fluids stored in the

reservoir to be produced from this original location

up to a point at the surface where they can be

separated, treated, processed, transported and

finally sold.


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3. This concept of oil well includes not only the so

called drilled well but also all other components that

are important for production, such as the reservoir,

perforations, flow lines, artificial lift equipment,

boosting equipment, chokes and any other

equipment that might interact with the fluids when

flowing from the reservoir up to the final separator.

Oil Well


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Oil Well Examples


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Fluid Production

Path of produced fluids

Reservoir

Perforations, gravel pack, etc.

Downhole equipment, casing, tubing.

Downhole artificial lift equipment

Mixed with lift gas or lift fluid

Wellhead, production chokes

Flow lines Mixed with production from other wells (manifolds)

Separator

Tank or Compressor


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Path of produced fluids


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Flow in Production System

Porous Media

Perforations

Production String

Downhole Equipment

Restrictions

Surface Flowline

Surface Equipment

RestrictionsProduction

Separator

Multiphase Pumpin System

Artificial Lifted Well

Long Production Flowlines

Compressed

Fluids in the

Reservoir


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Fluid Production

In each flow segment, the fluids interactwith the production components

Pressure and temperature changes.

Mixing with other fluids

Fluid properties constantly changing


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The Driving Force forProduction


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Driving Force

The driving force that moves fluids along the

reservoir and production system is the energy

stored in the form of compressed fluids in the

reservoir.

As the fluids move along the system components,pressure drop occurs. The pressure in the

direction of flow continuously decreases from thereservoir pressure to the final downstreampressure value at the separator.


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Driving Force


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Reservoir

Pressure

Individual

Components

Pressure,

Temperature and

Composition

Changes

Separation

Pressure( )cP q

rP

sP

Driving Force


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Natural Equilibrium Flowrate


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Natural Equilibrium Flowrate

The natural force that moves fluids in the system isthe reservoir pressure.

The reservoir pressure needs to overcome the

pressure drop in each of the components of thesystem and allow fluids to enter the separator.

Pressure drop in each production component is afunction of flowrate.

The flowrate value at which a specific well flows

using only the energy stored in the compressedreservoir fluids is called the natura l equi l ibr iumflowrate.


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Equilibrium Flowrate

The flowrate value at which a specific well

flows using only the energy stored in the

compressed reservoir fluids is called

natural equi librium f low rate.

( )r s cP P P q =


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Changes in Productionwith Time


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Production changes with

time As the reservoir is produced its pressure,

(driving force for producing fluids) naturally

declines. Appearance of a gas phase inside the porous

media also reduces the productivity of theliquid oil phase.

There are also changes in producingconditions such as Water-Oil Ratio, Gas-OilRatio, deposition of wax or scale, etc.


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Changes in Production

There is a reduction on the ability of the

reservoir to deliver fluids after the perforations

at a sufficient pressure to overcome the

pressure losses through the the production

system.

Therefore, the well seeks a new equilibrium

point of lower flowrate with lower pressurelosses in the reservoir and in the system.


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Changes inProduction

0

50 0

1000

1500

2000

2500

0 0.2 0.4 0.6 0.8 1 1.2 1.4 1.6

Cumulative Production (10^6 barrels)

EquilibriumF

lowrate

(bpd)

eq

0

50 0

1000

1500

2000

2500

0 200 400 600 800 1000

Time (days)

Equilibriu

mF

lowrate(bpd)

eq


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The natural equilibrium flowrate declines

with time

There are situations however, when such

an equilibrium point does not exist any

longer and the well cannot produce

naturally any more and ceases to be anaturally flowing well and dies.


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We need then to know:

What is the minimum equilibrium flowrate ?

Does the well let you know it will die ?

Can we forecast how long a well will produceunder natural flow conditions ?

Can we detect when a well is approaching the end

of the natural flow conditions life ?

After answering those questions we still haveone left:

Can we improve the ability of a well to produce

fluids ?


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Corrective Measures to

Increase Natural EquilibriumFlowrate


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Corrective Measures

In order to modify the natural equilibrium flowratedecrease that would occur with time we can usuallyact in three ways:

1. The first option is modify the production system toreduce the pressure drops by changing thephysical configuration of the system after theperforations:

Open Chokes

Tubing size Flowline size

Production Layout


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Corrective Measures

2. The second option is by increasing the ability of the reservoirto deliver fluids at higher pressures at the perforations

Water and gas injection in the reservoir

Stimulation techniques

Perforation Density

In both cases the well is s t i l l ca lled a natura l ly f lowin g

wel l s ince the equi l ib r ium f low rate w i l l be determ ined by

the abi l i ty of the reservo i r p ressure to ov ercome the

pressure drops in the system


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Corrective Measures

3. The third option is to install specific devices that willhelp the reservoir pressure to overcome thepressure drops in the system after the perforations.

This can be accomplished in two ways:

a. by a systematic injection of lift fluids that willreduce the gravitational pressure drop in thesystem (gas lift)

b. by using a pump to provide the additionalpressure increment to overcome part of thepressure losses in the system.


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Corrective Measures

In th is last case we have no more a

natura l ly f lowing wel l s ince now the

equi l ib r ium f lowrate wi l l be determ inedby the abi l i ty o f the reservoir p ressure to

overcome the pressure drops in the

system after the perforat ions with the

help o f an ex ternal sou rce o fhorsepower .


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Artificial Lift


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Artificial Lift

In the beginning of the oil industry it wasrecognized that the pressure of fluids insidethe porous media provided the necessaryenergy to lift the fluids to the surface.

Techniques that use an external source ofhorsepower to help the reservoir inovercoming the pressures losses in the

production system after the perforationsreceive the generic name of Ar t i f ic ial Li f t.


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Artificial Lift

Artificial lift is the area of petroleum engineering

that studies methods used to promote an

increase in the production rate of flowing wells

or to put wells back into production by using an

external horsepower source to help the reservoir

pressure to overcome the pressure drops in the

system downstream of the perforations.


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Artificial Lift Methods


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Artificial Lift Methods There are several artificial lift methods. The

most important ones are: Beam Pumping

Continuous Gas Lift

Electrical Submersible Pump

Progressive Cavity Pump Hydraulic Jet Pump

Intermittent Gas Lift

Hydraulic Pump

Plunger Lift Auto Gas Lift

Other Traditional Methods

Boosting Methods

Etc


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The definition of Artificial Lift Methods requires theexistence of a external horsepower source. Twocomments must be made regarding plunger lift and autogas lift.

Plunger Lift can be operated in 2 modes

Injecting supplemental gas. In this case it fits exactly the definitionof Artificial Lift Method

Without gas injection. In this case, there is no externalhorsepower source and plunger lift is considered an enhancednatural flow

Auto Gas Lift In auto gas lift the injected lift gas comes from a different

production zone. There is no surface horspeower source. Theexternal horsepower source is the lift gas zone. This can beconsidered as a natural flow of two zones being producedsimultaneously.


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Artificial Lift - Uses

In Oil Wells

Boost production

Put wells back into production

Stabilize production

In gas wells or CBM wells

To remove condensate or water from wells


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Pump

Sucker Rods

Tubing

Suffing Box

Polished Rod

Prime Mover

Pumping Unit Beam Pump


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Pump

Sucker

Rods

Tubing

Suffing Box

Polished Rod

Prime

Mover

Pumping

Unit

Beam Pump Familiar to engineers andoperators

Simple design Low capital investment for

low production at shallowto medium depths.

High investment for high

flowrates in deep wells. Allow very low fluid levels

(low bottom hole flowingpressure).

Adaptable to scale and

corrosion problems Limitation with casing size.

Adaptable to automation.

Not suitable for crookedholes


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Unloading Valve

Gas Lift Mandrel

Tubing

Operating Valve

Packer

Christmas Tree

Injection Choke

Continuous Gas Lift


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Unloading Valve

Gas LiftMandrel

Tubing

Operating Valve

Packer

ChristmasTree

Injection

Choke

Continuous Gas Lift Low investment for deepwells.

Most efficient for high GLR. Low operating costs for

sand production.

Flexible.

Adaptable to crooked holes.

Capable of producing veryhigh flowrates

Requires a source of highpressure gas.

Can not achieve very lowbotton hole flowingpressures.

Casing and lines mustwithstand gas pressure


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Primary Transformer

Switchboard

Wellhead andelectricmandrel

Tubing

Round Cable

Packer

Pump

Separator

Protector

Flat Cable

Motor

ElectricalSubmersiblePump


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PrimaryTransformer

Switchboard

Wellhead

and

electricmandrel

Tubing

Round Cable

Packer

Pump

Separator

Protector

Flat Cable

Motor

ESP Can produce very highflowrates from shallow to

medium depths. Low investment costs forshallow depths.

Adaptable to automation.

Casing size is not critical for

high flowrates. Electrical cable design is the

weakest link.

Needs a VSD to be flexible.

Requires a stable source of

electricity. Big problems with scale.

Requires workover toremove unit.


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Transformer

Polished Rod

Electric Motor

Christmas Tree

Control

Panel

Tubing

Rods

Downhole PCP

Gas Anchor

Anchor

Progressing Cavity Pump


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Christimas Tree

Tubing

Unloading Valve

Valve Mandrel

Operating Valve

Packer

Check Valve

Intermitor

Pressure Gas

Open

Closed



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Artificial Lift - Management

The management of artificial lift is a continuousprocess divided in 5 steps:

1. Selection of Artificial Lift Method

2. Evaluation of production conditions to define wellequipment, production levels, failure-control andmonitoring strategy to protect well equipment.

3. Monitoring of production data

4. Monitoring of equipment performance5. Evaluation of production equipment failure


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Artificial Lift - Management

Design and Selection

1 Artificial Lift Method

Selection

2 Artificial Lift Equipment

Operational Conditions

Failure Control

Monitoring Strategy

3 Monitoring Production Data

4 Monitoring Equipment Performance

5 Evaluation of Equipment Failure

Monitoring and Evaluation


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1 - Artificial Lift Management

The monitoring and evaluation phase mayresult in a new design and selection phase.

Change artificial lift method Example continuous gas lift intermittent gas lift

Change artificial lift method equipment type. Example install a downhole separator

Change equipment protection

Example corrosion or scale inhibitor

Change operational conditions Example change flow rates


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1 - Artificial Lift Method

As we will see there are severalartificial lift methods.

Each method has its own

characteristics. The best method is a balance of the

method capabilities, restrictions,production flowrates, investment and

operational costs with the objective ofmaximizing profit or maximizing theexpected profit.


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1- Artificial Lift Method

The number of the viable options and therelative advantages or disadvantages ofmethods for a specific application dependsstrongly on two factors:

Well Type

Onshore Offshore

Dry completion

Satellite well

Extremely Harsh Conditions (Artic, desert, etc)

Existing Infrastructure Remote well

New well in a new field

New well in a existing field

Existing well in a existing field


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Production conditions and constraints changein time.

The best artificial lift method is a function ofprevailing production conditions.

The best artificial lift method usually:

Is not the one that maximizes profit today

Is not the one that maximizes profit in a futurecondition.

The best artificial lift method is the one thatmaximizes ultimate profit.


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Usually maximization of ultimate profit isobtained by using different artificial liftmethods at different times during the life of awell.

The lift-changing capability advantages andcosts must be properly considered.

We must also know when those changesshould take place.

Example of Artificial Lift Changes

Continuous gas lift Intermittent gas lift Beam pumping Electrical Submersible Pump

Continuous gas lift Electrical Submersible Pump

Etc...


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In very few cases, a combination ofartificial lift methods may be the bestchoice.

Proper evaluation of the benefits andalso of the complexity of the systemmust be done.

Example of Artificial Lift Combinations

Gas lift and Electrical Submersible Pump Jet Pump and Electrical Submersible Pump

Etc...


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The proper selection of artificial lift system depends onseveral other disciplines such as drilling, completion,reservoir management, production layout, automation,etc....

Artificial lift should be considered since the beginningof the field development plan when reservoir, drilling,completion and production decisions are being made.

All known constraints, production conditions andfuture changes must be properly addressed.

This process requires good communication andinteraction between all correlated disciplines.


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2- Method Design and Operating Settings

Several Production Characteristics affects thisphase.

Bottomhole Temperature

Solids Production

Gas Production Corrosive fluids

Scale Problems

Stability

Changes in production conditions with time

Casing condition Etc...


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Why So Many Options ?


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There are several artificial lift methods. Themost important ones are: Beam Pumping

Continuous Gas Lift

Electrical Submersible Pump Progressive Cavity Pump

Hydraulic Jet Pump


Hydraulic Pump

Plunger Lift Auto Gas Lift

Other Traditional Methods

Boosting Methods


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Selection


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Factors Affecting the Selection of



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Artificial Lift Methods Factors to be considered:

Flowrates (reservoir pressure and productivity index) GLR and WC behavior

API and viscosity

Depth of well and temperature

Condition of casing

Type of well (vertical or directional) Sand production, wax, emulsion corrosion and scale

conditions

Type and quality of energy available

Environment and environmental issues

Personnel training and experience

Capital investment and operational costs

Reliability

Data quality and uncertainty

Existing Infrastructure

Etc....


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Artificial Lift MethodsExample of Attribute Table

FairFairExcellentLow Flowrates

ExcellentFairFairFlexibility

ExcellentFairFairDepth

GoodExcellentPoorHigh FlowratesExcellentPoorPoorHigh GOR

PoorGoodPoorWax

ExcellentFairFairSand

Gas L i f tESPRod PumpParameter

What is good, fair, poor and excellent ?

Do we have the same scale to compare methods?

Do we use the same scales ?


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Artificial Lift Methods Attribute Tables

The information on those tables should be used as a

guideline in selecting a method for a specific application. It is very hard to find an average attribute value for a

certain application

Most of the times the following factors override theinformation on the tables.

Location Onshore

Offshore

Artic

Etc..

Existing Infrastructure Remote well

New well in a new field

New well in a existing field

Existing well


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The method selection sometimesbecomes a personal decision. Operators,

service companies, product manufacturermay have some preferences not usuallyjustified by a technical analysis.


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Several attribute tables are available in theliterature. Brown, Clegg-Bucaram-Hein, Neely, etc...

They were developed as a aid in comparingeach artificial lift method for each production

characteristic. They contain a dynamic information and

should be updated to reflect newdevelopments or limitations of the technology

The attributes can be classified into 3 types:1. Design Considerations and Overall Comparisons

2. Normal Operating Conditions

3. Artificial Lift Considerations


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Artificial Lift Methods AttributeTables

Clegg, J.D., Bucaram, S. M., Hein, N. W. Jr. New Recommendations andComparisons for Selecting Artificial Lift Methods, SPE 24834 - 1992.


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Table I Artificial Lift Design Considerations and Overall Comparisons

Good for low

volume wells. Canadjust injection

time andfrequency.

Good: must adjustinjection time andcycles frequently.

Excellent: gas

injection rate variedto changes rates.

Tubing needs to besized correctly.

Good to excellent:power fluid rate

and pressure

adjusts theproduction rate and

lift capacity.Selection of throatand nozzle sizesextend range of

volume andcapacity.

Good/excellent:Can vary powerfluid rate and

speed of downholepump. Numerouspump sizes and

pump/engine ratiosadapt to productionand depth needs.

Poor: pumpsusually run at a

fixed speed.

Requires carefulsizing. VSD

provides moreflexibility but addedcosts. Time cyclingnormally avoided.

Must size pumpproperly.

Fair: can alter

speed. Hydraulicunit provides

additional flexibilitybut at added cost.

Excellent: can afterstroke speed andlength , plunger

size, and run time

to controlproduction rate.

Flexibility

Excellent forflowing wells. No

input energyrequired because ituses the energy of

the well. Goodeven when small

supplementary gas

is added.

Poor: normallyrequires a highinjection gas

volume/barrel fluid.Typical lift

efficiency is 5% to10%; improvedwith plungers.

Fair: increase forwells that require

small injectionGLRs. Low for

wells requiring highGLRs. Typical

efficiencies of 20%but range from 5%

to 30%.

Fair to poor.Maximum

efficiency only

30%. Heavilyinfluenced by

power fluid plusproduction

gradient. Typicaloperating

efficiencies of 10%to 20%.

Fair to good: not asgood as rod

pumping owing toGLR, friction, and

pump wear.Efficiencies range

from 30% to 40%with GLR>100;

may be higher withlower GLR.

Good for high ratewells but

decreasessignificantly for


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Fair. Some trade invalue. Poor open

market value.

Fair: some trade invalue. Poor open

market value

Fair: some marketfor good used

compressors andsome trade in

value for mandrelsand valves.

Good: easily

moved. Sometrade in value. Fairmarket for triplex

pumps.

Fair market fortriplex pumps;good value for

wellsite system that

can be movedeasily.

Fair: some trade invalue. Poor openmarket values.

Fair/poor: easilymoved and somecurrent market for

used equipment.

Excellent: easilymoved and goodmarket for used

equipment

Salvage Value

Good if wellproduction is

stable.

Excellent if there isan adequate

supply of gas andan adequate lowpressure storage

volume for injection

gas. System mustbe designed for theunsteady gas flow

rates.

Excellent if

compressionsystem properly

designed andmaintained.

Good with properthroat and nozzle

sizing for theoperating

conditions. Mustavoid operating incavitation range of

jet throat; related topump intake

pressure. Moreproblems if

pressures > 4000psig.

Good with acorrectly designed

and operatedsystem. Problems

of changing wellconditions reducedownhole pump

reliability. Frequent

downtime resultsfrom operational

problems.

Varies: excellentfor ideal lift cases;poor for problems

areas. Verysensitive tooperating

temperatures and

electricalmalfunctions.

Good: normally

over pumping andlack of experience

decreases runtime.

Excellent: run timeefficiency >95% if

good operating

practices arefollowed and ifcorrosion, wax,asphaltenes,

solids, deviations,etc. are controlled.

Reliability

Usually very low.Same as

continuous flow

gas lift.

Well costs low.Compression costs

vary depending onfuel and

compressormaintenance. Key

is to inject asdeeply as possiblewith optimum GLR

Higher power cost

owing to

horsepowerrequirement. Low

pump maintenancecost typical withproperly sized

throat and nozzle.

Often higher than

rod pumps even forfree systems. Shortrun life increases

total operatingcosts.

Varies: if

horsepower is high,

energy costs arehigh. High pullingcosts result from

short run life. Oftenrepair costs are

high.

Potentially low, butshort run life onstator frequently

reported.

Very low for

shallow to mediumdepth (


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Essentially a lowliquid rate, highGLR lift method.Can be used forextending flow lifeor improving

efficiency. Ample

gas volume and/orpressure neededfor successfuloperation. Used on


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Time Cycle isnecessary for

efficient operation.Pump Off is not

applicable.

Poor: cycle mustbe periodicallyadjusted. Labor

intensive.

Not applicable.

Poor: does notappear applicableowing to intake

pressure

requirement higherthan pump-off

Poor: possible butnot normally used.Usually controlled

only by

displacementchecks, pump-off

control notdeveloped

Poor: soft start andimproved

seals/protectors

recommended.

Poor: avoidshutdown in highviscosity/sand

producers.

Excellent if wellcan be pumped off.

Time cycle andPump-off Controller

Application

Well testing simplewith few problems

Poor: well testing

complicated byinjection gasvolume/rate.

Measurement ofboth input andoutflow gas a

problem.Intermittent cancause operating

problems with

separators.

Fair: well testingcomplicated by

injection gasvolume/rate.

Formation GLRobtained by

subtracting totalproduced gas frominjected gas. Gas

measurement

errors common

Same as hydraulic

reciprocatingpumps. Three

stage productiontest can be

conducted byadjusting

production steprates, pressured

recorder in place tomonitor intake

pressure

Fair: well testingwith standard

individual well unitspresents few

problems. Welltesting with a

central systemmore complex:

requires accuratepower fluid

measurements

Good: simple withfew problems. Highwater cut and high

rate wells mayrequire a free-

water knock-out.

Good: well testingsimple with few

problems.

Good: well testingis simple few

problems usingstandard available

equipment and

procedures.

Testing

Table II Normal Operating Considerations

Good: depends ongood well tests and

well pressure chart

Fair: complicatedby standing valve

and fallback.

Good/excellent:can be analyzed

easily. Bottomholepressure andproduction logsurveys easily

obtained.Optimization andcomputer controlbeing attempted

Same as hydraulicreciprocating

pumps.

Good/fair:downhole pump

performance can

be analyzed fromsurface power-fluid

and pressure,

speed, andproducing rate.

Bottomhole

pressure obtainedwith free pumps

Fair: electricalchecks but specialequipment needed

otherwise

Fair: analysisbased on

production andfluid levels only.

Dynamometersand pump-off cardsnot possible to use.

Excellent: can beeasily analyzed

based on well test,fluid levels, etc.

Analysis improved

by use ofdynamometers and

computers.

Surveillance

None normallyrequired.

Same ascontinuous gas lift.

Good: engines,turbines, or motors

can be used for

compression.

Same as hydraulicreciprocating

pumps.

Excellent: prime

mover can beelectric motor, gas,

or diesel firedengines or motors.

Fair: requires a

good power sourcewithout spikes or

interruptions.Higher voltagescan reduce I2R

losses.

Good: bothengines or motors

can be used.

Good: bothengines or motorscan be used easily

(motors more

applicable andflexible).

Prime MoverFlexibility

Plunger LiftIntermittent Gas

LiftContinuous Gas

LiftHydraulic Jet

Systems

HydraulicReciprocating

Pumping

ElectricalSubmersible

Pumping

Progressing CavityPumping

Sucker RodPumping

Attribut e


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Excellent.Same as

continuous flow

Excellent:produced gas

reduces need forinjection gas

Similar to hydraulicreciprocating

pump. Free gasreduces efficiencybut helps lift. Vent

free gas if possible.Use a gas anchor

Good/fair:concentric fixedpump or parallelfree permits gas

venting withsuitable downhole

gas separatorbelow pump intake.Casing free pump

limited to low GOR.

Poor for free gas(i.e. > 5%) throughpump. Rotary gasseparators helpful

if solids not

produced.

Poor if must pumpany free gas.

Good if can ventand use natural

gas anchor withproperly designedpump. Poor if must

pump >50% freegas.

Gas handling ability

No knowninstallations.

Same ascontinuous flow

Fair: dual gas liftcommon but goodoperating of dual

gas lift complicated

and inefficientresulting in

reduced rates.Parallel 2x2 in.nominal tubing

inside 7 in. casingand 3x3 in. tubinginside 9 5/8 in.casing feasible

Same as hydraulicreciprocating pump

except canpossibly handle

higher GLR but atreduced efficiency

Fair: three stringnonvented

applications havebeen made with

complete isolationof production and

power fluid fromeach zone. Limited

to low GLR andmoderate rates.

No knowninstallations. Larger

casing would beneeded. Possible

run and pullproblems.

No knowninstallations.

Fair: parallel 2 x 2in. low rate duals

feasible inside 7 in.casing. Duals

inside 5.5 in.casing currently notin favor. Gas is a

problem from lower

zone. Increasedmechanical

problems

Duals application

Table III Artificial Lift Considerations

Excellent.Same as

continuous flow

Excellent: fewwireline problemsup to 70 degree

deviation forwireline retrievable

valves

Excellent: short jet

pump can passthrough doglegs upto 24 degree/100ft. in 2 in. nominal

tubing. Sameconditions as

hydraulicreciprocating

pump.

Excellent. If tubing

can be run in thewell, pump

normally will passthrough the tubing.

Free pumpretrieved without

pulling the tubing.Feasible operationin horizontal wells.

Good: fewproblems. Limited

experience in

horizontal wells.Require long radiuswellbore bends to

get through.

Poor to fair:

increased load and

wear problems.Currently, very fewknown installations.

Fair: increased

load and wearproblems. Highangle deviated

holes (>70degrees) and

horizontal wells are

being produced.Some success in

pumping 15degrees/100 ft.

using rod guides.

Crooked/deviatedholes

Fair: normalproduction cycle

must be interruptedto batch treat to

well.

Same as

continuous flow

Good: inhibitor in

the injection gasand/or batch

inhibiting downtubing feasible.Steps must betaken to avoid

corrosion ininjection gas lines.

Good/excellent:inhibitor with power

fluid mixes withproduced fluid at

entry of jet pumpthroat. Batch treat

down annulusfeasible.

Good/excellent:

batch orcontinuous treating

inhibitor can becirculated withpower fluid for

effective control.

Fair: batch treatinginhibitor only to

intake unlessshroud is used.

Good: batchtreating inhibitor

down annulusfeasible

Good to excellent:

batch treatinginhibitor downannulus used

frequently for bothcorrosion and scale

control.

Corrosion/scale

handling ability

Plunger LiftIntermittent Gas

LiftContinuous Gas

LiftHydraulic Jet

Systems

HydraulicReciprocating

Pumping

ElectricalSubmersible

Pumping

Progressing CavityPumping

Sucker RodPumping

Attribut e


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Sand can stickplunger; however,

plunger wipestubing clean

Fair: standing valve

may causeproblems.

Excellent: limit isinflow and surfaceproblems. Typicallimit is 0.1 % sand

for inflow andoutflow problems.

Fair/good: jet

pumps areoperating with 3%sand in produced

fluid. Power fluid to

jet pump cantolerate 200 ppm of25 micron particlesize. Fresh watertreatment for saltbuildup possible

Poor: requires


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Excellent: for lowflow rates of 1 to 2B/D with high GLR.

Good: limited by

efficiency andeconomic limit.Typically to 4

bbl/cycle with up to48 cycles/day

Fair: limited byheading and

slippage. Avoidunstable flow

range. Typicallylower limit is 200

B/D for 2 in. tubingwithout heading;

400 B/D for 2.5 in.and 700 B/D for 3

in tubing.

Fair: >200 B/Dfrom 4000 ft

Fair: not as goodas rod pumping.Typically 100 to

300 B/D from 4000to 10000 ft. >75

B/D from 12000 ftpossible

Generally poor:lower efficiencies

and high operatingcosts for


81/145


After selection of potential choices, acareful, realistic and detailed design of thesystem must be made.

This phase is extremely important, since apoor or neglected design may ruin theadvantages of a certain option resulting ina very bad performance for a otherwise

excellent choice.


82/145


After designing the appropriate candidates, afinal realistic economic analysis will indicate thebestchoice.

Maximization of ultimate profit is the goal.

The economic analysis requires Investment costs and Salvage values

Operational costs Artificial Lift system performance

Production Forecast

Failure rate estimate under the expected operating conditions

Oil, gas and energy prices and method flexibility

Etc...

O O


83/145

Our Objective

Our objective Is not to maximize production

Is not to minimize operational costs

Is not to minimize investment costs

Is not to minimize downtime

Our objective Is to maximize profit through an intelligent

management of operational and investment costs. Awell designed system will balance costs, productionand reliability under the various physical, economical

environmental, human and technical constraints. We are in the business of producing profit

through oil, gas and water production.

I C


84/145

Investment Costs

The investment costs for a artificial liftmethod for a certain application arefunction of:

Flowrate

Lifting depth

Setting depth


85/145


86/145

Investment Costs AN EXAMPLE

The following tables and graphs are based on: Johnson, L. D.: Here are Guidelines for Picking an Artificial Lift

Method - The Oil and Gas Journal, August 26, 1968.

In estment Costs


87/145

Investment Costs

Lift Depth (ft)

Rod Pumping Investment Costs (US$)

Flowrate(bpd)

26180176901100

23220165901000

2062016190900

287102040015700800

252902021012950700

31150229901838011840600

3285025990191601587010720500

2848026570222101737013630986540025480220501876014410119358635300

21640197701600012845101157455200

1993016520135951123586756345100

700060005000400030002000

I t t C t


88/145

Investment Costs

Lift Depth (ft)

Hydraulic Pumping Investment Costs (US$)

Flowrate(bpd)

3783035610331903077028350259351100

3513033210308902857026250239301000

347903247030150278302551023190900

292102729025370234502153019610800

269802506023140212201930017380700

239202230020680190601744015820600

239202230020680190601744015820500

229302131019690180701645014830400217502013018510168901527013650300

211601954017920163601475013140200

203401872017100154801386012240100

700060005000400030002000


89/145

Investment Costs

Lift Depth (ft)

Electrical Submersible Pumping Investment Costs (US$)

Flowrate(bpd)

2647026470264702647026470264701200

2274022740227402274022740227401000

189001890018900189001890018900800

156501565015650156501565015650600121701217012170121701217012170400

700060005000400030002000


90/145

Beam Pumping

0

5000

10000

15000

20000

25000

30000

35000

0 200 400 600 800 1000 1200

Flowrate (bpd)

InvestmentCost(US$)

Lift Depth (ft) 7000 6000 5000

4000

3000

2000


91/145

Hydraulic Pumping

0

5000

10000

15000

20000

25000

30000

35000

40000

0 200 400 600 800 1000 1200

Flowrate (bpd)

InvestmentCo

st(US$)

Lift Depth (ft)

7000

5000

3000

2000


92/145

Regions of Minimum Investment


93/145

Lift Depth = 5000 ft

0

5000

10000

15000

20000

25000

30000

35000

40000

0 200 400 600 800 1000 1200

Flowrate (bpd)

InvestmentCos

t(US$)

Artificial Lift Method

Beam Pumping

Hydraulic Pumping

Electrical Submersible Pump




94/145

Beam - Hydraulic - Electrical Submersible

Pumping

0

5000

10000

15000

20000

25000

30000

35000

40000

0 200 400 600 800 1000 1200

Flowrate (bpd)

InvestmentCost

(US$)

Lift Depth (ft)

7000

6000

5000

4000

3000

2000


Minimum Investment Regions


95/145

2000

3000

4000

5000

6000

7000

0 200 400 600 800 1000 1200

Flowrate (bpd)

Lift

Depth(ft)

Beam Pumping

Hydraulic Pumping

Electrical Submersible Pumping

Not necessarily Application Window

Operational Costs


96/145

Operational Costs

The operational costs should also be considered

when selecting an artificial lift method. Usually the operational cost should not be the only

criteria for selecting a artificial lift method. Theoperational cost should be an imput to the economicalanalysis to be performed.

Operational cost is consituted by three terms: Fixed Costs

Costs that do not depend on the production but occur on aregular basis

Variable Costs Costs that are directly related with the production levels and

occur on a regular basis Workover Costs

Costs that are related with failure of the system or componentsof the system and occur at certain points in time.

O C


97/145

Operational Costs

C = Daily Operational Cost

Cfixed = Fixed Operational Cost

Cv(q) = Variable Operational Cost

Cworkover = Workover Cost

workovervfixed CqCCC ++= )(

V i bl O ti l C t


98/145

Variable Operational Costs

The variable operational costs consist of the costs to lift, treat,produce, discard, export all the produced fluids.

We can break it down into each specific fluid variableoperational cost.

Another component of the operational cost consist of the cost of

energy used to help producing the fluids from the bottom of thewell to the surface (lift cost).

HPCqCqCqCC hpggwwoov +++=

V i bl O ti l C t


99/145


Each individual fluid production is associated withthe oil production. The energy consumption is alsoassociated with the oil production

)()()( ohpoopgoopwoov qHPCqqGORCqqWORCqCC +++=

WORp = Production Water Oil Ratio

GORp = Production Gas Oil Ratio

V i bl O ti l C t


100/145


)()()( ohpoopgopwov qHPCqqGORCqWORCCC +++=

The right hand side can be lumped into a equivalent

production operational cost

)()( ohpooe

ov qHPCqqCC +=

)()( opgopwoe

o qGORCqWORCCC ++=


101/145


102/145

Optimum Production Flowrate


103/145


The total operational cost then can be written as:

)()( ohpooe

oworkoverfixed qHPCqqCCCC +++=

CSP =

During normal production, the daily profit from thewell can be written as:

)()()( ohpooe

oworkoverfixedoo

e

o qHPCqqCCCqqSP =



104/145


( ) )()()( ohpworkoverfixedooe

oo

e

o qHPCCCqqCqSP =

Simplifying the notation:

)()( ohpworkoverfixedooe

o qHPCCCqqPP =

)()()( oeooeooeo qCqSqP =



105/145


0)(

)()(

=+=

o

ohpo

e

oo

o

o

e

o

o

dq

qdHPCqPq

dq

qdP

dq

dP

The maximum daily profit will occur when:

0=

odq

dP



106/145


hp

e

o

o

e

oo

o C

Pdq

dPq

dq

dHP+

=

The opt imum produ ct ion flowrateis the solutionto the following equation:

The relationship between the HP and the wellequilibrium flowrate qo is extremly important to

determine the optimum profit flowrate. Therelationship between the equilibrium flowrate andthe horsepower consumption is called Ar t i f ic ia l Li f tMethod Performance Curve.

Artificial Lift Performance Curve


107/145

Artificial Lift Performance Curve TheArtificial Lift Method Performance Curve can be

obtained through a nodal analysis of the system.

0

200

400

600

800

1000

1200

1400

1600

0 200 400 600 800 1000

Horsepower

EquilibriumF

lowra

te-

nf

e

qMaximum Profit

hp

o

e

o

o

oeoo

o

o

C

qPdq

qdPq

dq

qdHP)()(

)(+

=

Artificial Lift Performance


108/145


A artificial lift system should be designed to operate at the

optimum profit flowrate. The optimum profit flowrate is function of:

Artificial Lift Method Characteristics and specific design

Reservoir Inflow Performance and Production Characteristics

Fluids sale prices, operational costs and energy costs

When determining the method performance curve, allrestricitions must be considered in order to obtain a realisticcurve describing the application envelope of the method. Asa result the performance curve may not be complete asshown in the last picture The performance curve may be limited by factors such as:

Minimum flowrate to achieve stable production conditions.

Maximum or minimum conditions for operation of the system orcomponents of the system.

Equipments installed



109/145


0

200

400

600

800

1000

0 100 200 300 400 500

Horsepower (HP)

OilFlowrate

(bpd)

Design Point

Maximum Motor HP

Minimum Stable Flowrate

Gas Fraction = 15%

VSD Operating Envelope



110/145


Another important characteristics that helps to select anartificial lift method is the method flexibility around thedesign flowrate on the method performance curve. Thiswill help to evaluate the effects of:

Changes in the method performance due to changes in the

economical parameters Changes in the method performance due to uncertainties in the

design data

Changes in the method performance due to changes inproduction conditions with time.



111/145

The flexibility of the method is a function of the

equipment installed to provide flowrate control. The typeof control equipment installed may also change themethod performance curve.

Flowrate control can be obtained by: Changing surface equipment operating parameters

Choke Size

VSD Frequency

Gas Injection Pressure

Stroke length and SPM

Etc

Changing sub-surface equipment.

Oriffice of Gas Lift Valve Etc

Sometimes extension of a method flexibility is onlyaccomplished by a complete redesign of the system anda complete workover job.



112/145


0

200

400

600

800

1000

0 100 200 300 400 500

Horsepower (HP)

OilFlowrate

(bpd)

Design Point

Minimum Stable Flowrate

Gas Fraction = 15%

Choke Control Operating Envelope

Pump Minimum Operating Flowrate without a VSD



113/145


0

200

400

600

800

1000

0 100 200 300 400 500

Horsepower (HP)

OilFlowrate

(bpd

Design Point

Maximum Motor HP or Pump Range

Minimum Stable or Pump Range Flowrate

N por

Pr



114/145


The performance curves behavior withcumulative production is an extremly powerfulanalysis tool. We can predict: Method performance during a certain depletion period

Method performance taking into consideration all

conditions and limitations imposed or intrinsic to thesystem or method.

Method flexibility in following the best economicproduction flowrate during the depletion period.

Method flexibility and its impact on the economics

during the production period.



115/145

The performance curve enables the determination of thebest (maximum daily profit) production strategy(equilibrium flowrate and horsepower) to be used as afunction of depletion for a certain design reflecting actualproduction conditions and limitations.

Depending on the method flexibility and the performancecurve limitations, the optimum prodcution strategy mayconincide or not with the optimum production flowrate.




116/145

The relationship between the equilibriumflowrate and cumulative production isfundamental for an accurate production forecastof the system.


dt

Nq

dN

pe

p=

)(



117/145

Solution of this ODE will enable us to determine:

dtetqetdNdNt

k

it

k

i

p

pv

p

nn

== )()(

)(tNp )(tqe

We can then estimate the cumulative production present

value from:

If a forecast for oil sale and production costs is known we can also calculate theeconomic present value for the system



118/145

The procedure outlined enables the determination of theoptimum operating parameters for a certain artificial lift

method design. For a certain design, the procedure will yield the

production strategy that will maximize daily profit underthe system conditions and restrictions.

The procedure will optimize the present value for

operating the well under a certain design. The procedure will not globally optimize present value due

to: Method flexibility and performance curves limitations due not allow

a certain design to produce at the best economical flowrate

possible. Optimum economical flowrate is outside the productionenvelope for that design.

For different depletion stages different designs will yield differentperformance curves.

The system will eventually fail and a well intervention will berequired to put the system back into a safe operating condition



119/145

0

200

400

600

800

1000

0 100 200 300 400 500

Horsepower (HP)

OilFlowrate

(bpd)

Optimum Economical Flowrate

Production Strategy

Production Envelope

System Failure


120/145



121/145

Each artificial lift method or artificial lift

method application scenario will have: Different expected lifes

Different duration and costs associated with a

complete workover job. Different costs and options associated with a

simpler intervention to improve efficiency.

Different waiting line times.

Different changes in performance withdepletion

Artificial Lift Performance - Example


122/145

0

5000000

10000000

15000000

20000000

25000000

30000000

35000000

40000000

45000000

50000000

0 500 1000 1500 2000 2500 3000 3500 4000

Time (days)

NominalProfit

(US$)

MTBF 720 Days

Workover Time 30 Days

Waiting Time 120 Days

Design Efficiency

No Failure 100% Performance Efficiency Design

Failure

Waiting Time

Workover


123/145

All those effects are important to determinefor each scenario:

Total life span Number of design changes during life span

Best design strategy for each period



124/145

Optimum Flowrate and Artificial Lift Performance Curve


125/145

The Artificial Lift Method Performance Curve can be

obtained through a nodal analysis of the system.

0

200

400

600

800

1000

1200

1400

1600

0 200 400 600 800 1000

Horsepower

EquilibriumF

lowrate-

nf

eqMaximum Profit

hp

o

e

o

o

o

e

oo

o

o

C

qPdq

qdPq

dq

qdHP)()(

)(+

=


126/145

Optimum Flowrate and Artificial Lift


127/145

pPerformance Curve

The Performance curve can be used to:

Determine the best operating conditionwhen the system and the reservoir

performance and production characteristicsare known. This is usually the approach tooptimize production conditions.

Design a artificial lift method to be installed

in a well when the reservoir performanceand production characteristics are known.



128/145

The Performance curve also illustrates animportant problem.

Production forecast should be conducted toreflect the future reservoir behavior as well asthe future operating conditions of the

production and artificial lift system. This problem can only be solved in an

integrated way, since production operatingconditions will depend on future reservoir

behavior and reservoir behavior will dependon production history which is of coursecontrolled by production operating conditions.



129/145

Usually this problem is solved by a Nodal Analysis

The Nodal Analysis is conducted using OPR curvesthat reflect the production system and artificial liftbehavior and a reservoir simulator to reflect thereservoir performance and production characteristics.

As we have seen, there are several equilibriumconditions between the OPRs and the reservoirbehavior that are reflected by the artificial liftperformance curve for a certain level of reservoirdepletion.

The correct equilibrium point should reflect the actual

conditions to be used during the operation of the well. The well should be operated as close as possible to

the optimum economical flowrate.



130/145

This provides a criteria for the reservoirsimulator to select the best operating flowratefrom all the possible values from the OPRs.

The optimum production flowrate is given by:

hp

e

o

o

e

oo

o C

Pdq

dPq

dq

dHP+

=



131/145

When the IPR is not known, the left hand sidecan be written as:

o

wf

wfoo dq

dP

P

HP

q

HP

dq

dHP

+

=

The optimum production flowrate is given thenby:

hp

eo

o

e

oo

o

wf

wfo C

PdqdPq

dq

dP

P

HP

q

HP+

=

+



132/145

The criteria for the optimum flowrate is:

hp

e

o

o

e

oo

o

wf

wfo C

Pdq

dPq

dq

dP

P

HP

q

HP+

=

+

Production SystemBehavior

ReservoirBehavior

Economics andProduction Conditions

Managing Production


133/145

a ag g oduct o

Managing the production characteristicsof each individual well can also havedramatic effects on the economicresults.

Example 347 Wells

qo 10 - 20 bpd

qw 0 - 176 bpd

Managing Production


134/145

g g

0

5000

10000

15000

20000

25000

30000

0 5000 10000 15000 20000 25000 30000

Water Production (bpd)

OilProduct

ion(bpd)

Managing Production


135/145

g g

If we can really isolate and identify thefixed, variable and energy cost we canoptimize a pool of wells responding tochanges in the oil price.

HPCqCqCqSCP hpwwoooof =+

So = 15 US$/stb

Co = 4.9 US$/stb

Cw = 4.9 US$/stb

Chp = 1 US$/(HP day)

HP= 0.1 HP/stb (water or oil)


136/145

Managing Production


137/145

g g

So = 11 US$/stb

Co = 4.9 US$/stb

Cw = 4.9 US$/stb

Chp = 1 US$/(HP day)

HP= 0.1 HP/stb (water or oil)

Managing Production


138/145

g g

0

10000

20000

30000

40000

50000

60000

70000

80000

0 5000 10000 15000 20000 25000 30000

Oil Production (bpd)

Profit+Fixed

Cost(US$/d

Managing Production


139/145

g g

0

20000

40000

60000

80000

100000

120000

140000

160000

0 5000 10000 15000 20000 25000 30000

Oil Production (bpd)

Profit+FixedCost(US$/d)

15 US$/stb

11 US$/stb

Interesting Data


140/145

g

1,027Cubic Feet of Natural Gas

61,066HP day

3,412KWh of Electricity

5,800,000Barrel of Crude

21,400,000Ton of coal (907.2 kg)

Energy Content orEquivalence (BTU)

Energy Source

1 barrel*psi = 1.0389 BTU

Energy Content Equivalence


141/145

gy q

1,027

3,412

61,066

5,800,000

21,400,000

BTU

Cubic Feet ofNatural Gas

KWh ofElectricity

HP day

Barrel ofCrude

Ton of coal(907.2 kg)

Cubic Feet ofNatural Gas

KWh ofElectricity

HP dayBarrel ofCrude

Ton of coal(907.2 kg)

1

3.31

60181

56471700951

2083762723503.71

1 barrel*psi = 1.0389 BTU

1 bpd*psi is equivalent to 1.79 10-7 barrels of oil / day

References


142/145

1. Brown, K. E.: Overview of Artificial Lift Systems, SPE 9979, 1982.

2. Brown, K. E.: The Technology of Artificial Lift Methods, Vol. II-B, Chapter

9, Pennwell Books, Tulsa, OK, 1979.

3. Bucaram, S. M. & Patterson, J. C. Managing Artificial Lift, JPT April 1994,

SPE 26212.

4. Bucaram, S. M., Sullivan, J. H. A Data Gathering and Processing System toOptimize Production Operations, Journal of Petroleum Technology,

February 1972.

5. Bucaram, S. M., Yeary, B. J. A Data Gathering and Processing System to

Optimize Production Operations: A 14-Year Overview, Journal of Petroleum

Technology, April 1987.

6. Clegg, J.D., Bucaram, S. M., Hein, N. W. Jr. New Recommendations and

Comparisons for Selecting Artificial Lift Methods, SPE 24834 - 1992.

References


143/145

7. Clegg, J.D., Bucaram, S. M., Hein, N. W. Jr. Recommendations and

Comparisons for Selecting Artificial Lift Methods, JPT December 1993.

8. Clegg, J. D., High Rate Artificial Lift, SPE 17638, Journal of Petroleum

Technology, March 1988.

9. Corteville, J., Hoffmann, F., Valentin, E. Activation des Puits: Critres de

Slection des Procds. Revue de Linstitut Franais du Ptrole, Vol. 41,

NO. 6, November 1986.

10. Duke, S.: Artificial Lift Which Method Best Fits your Needs ?,

Southwestern Petroleum Short Course 1981.

11. Fleshman, R., Lekic, H. O., Artificial Lift for High Volume Production

1999.

12. Jacobs, E. G. Artificial Lift in the Montrose Field, North Sea, SPE 15869

1986.

13. Johnson, L. D. Here are Guidelines for Picking an Artificial Lift Method,

The Oil and Gas Journal, August 1968.

References


144/145

14. Kahali, K., Rai, R., Mukerjie, R. K. Artificial Lift Methods for Marginal

Fields, SPE 21696 1991.

15. Lea, J. F., Winkler, H. W. New and Expected Developments in Artificial Lift,

SPE 27990 1994.

16. Lea, J. F., Adisoemarta, P. S., Nickens, H. V. Artificial Lift for Horizontal

Wells, ETCE/OMAE 2000 Joint Conference Energy for the New

Millenium, February 14-17, 2000 New Orleans, LA.

17. Lea, J. F., Cox, J. C., Adisoemarta, P. S. Artificial Lift for Slim Holes, SPE

63042 2000.

18. Naguib, M. A., Shaheen, S. E., Bayoumi, E., Eman, N. A. Review of

Artificial Lift in Egypt, SPE 64508 2000.

19. Naguib, M. A., Bayoumi, A., Battrawy, A. Guideline of Artificial Lift Selection

for Mature Field, SPE 64428 2000.

20. Neely, A. B.:A. B. Neely Discusses Artificial Lift Techniques, Uses and

Developments. Journal of Petroleum Technology September 1980.

References


145/145

21. Neely, A. B., Gbison, F., Clegg, J., Capps, B., Wilson, P. Selection of

Artificial Lift Method, SPE 10337 1981.

22. Renfu, W., Xlankan, C. Artificial Lift Techniques in China, SPE 14866

1986.

23. Saputelli, L. Combined Artificial Lift System An Innovative Approach,

SPE 39041 1997.

24. Stair, C. D., Artificial Lift Design for the Deepwater Gulf of Mexico, SPE

48933 1998.

25. Valentin, E. P., Hoffmann, F. C. OPUS: An Expert Advisor for Artificial Lift,

SPE 18184 1988.

26. William B., Gargord, D. W.: High Capacity Artificial Lift Alternatives in the

Offshore Environment. European Offshore Petroleum Conference and

Exhibition 1978 SPE 8070.

artificial lift dude

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