Artificial Lift System L

8/16/2019 Artificial Lift System L

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ARTIFICIAL LIFT SYSTEMTypes

Selection, requirements & identification

PROF. DR. ARIFFIN SAMSURI

MYP 2513


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Students must be able to:

– Distinguish different type of artificial lift system

– Identify & select the requirement for artificial liftsystem

ARTIFICIAL LIFT SYSTEM – LEARNING OUTCOMES


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– Purpose:

To maintain a reduced producing bottom hole pressure so that formation

can give desired reservoir fluids required flowing bottom hole pressure

can be maintained for certain q

– Design basis:

Maintaining required flowing bottom hole pressure for desired q

– Requirement based on:

• When well produced less than desired q

• When well dead

INTRODUCTION


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Artificial Lift Fundamental

Reservoir pressure so low static fluid level below wellhead no natural flowIf PI sufficiently high & produced fluid contains enough gas flowing fluid pressure gradientgives positive wellhead pressure well can flow but need kicked off by swabbing or othertechniques


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Artificial Lift Fundamental

Pump installed create limited drawdown q


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Maximises Potential Drawdown & q

Deeper pump create larger drawdown on formation & maximum potential production can

be achieved


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• Available types: – Sucker rod pump

– Progressive cavity pump – PCP

– Hydraulic pump – Electrical submersible pump (ESP)

– Electrical submersible progressive cavity pump (ESPCP)

– Rotating rod pump

– Sonic pump

– Plunger lift

– Gas lift

– etc

ARTIFICIAL LIFT SYSTEM TYPE


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Various Artificial Lift Technique/Method

Most popular artificial lift type


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Pump Classification


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• Philosophy :• for maximum potential, select most economical type/system

• Methods or steps include:

– Operator experience – Method available for installation @ certain area – Possibility of working in adjoining or similar field – Method will lift @ desired q from required depth – Evaluating advantages & disadvantages – Expert system to both eliminate & select system – Evaluation of initial cost, operating costs, production

capabilities, etc

SELECTION CONCEPT


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• Generally should consider:• geographic location,• capital cost,• operating cost,• production flexibility,

• reliability,• mean time between failures,• reservoir pressure,• well productivity,• reservoir fluids,• long-term reservoir performance &

• facility constraints

• In most cases, what has worked best or which lift method performs best in similar field serveas selection criteria, together with consideration on equipment services available

type/system which provides highest present value for project life will beselected

SELECTION CONCEPT – cont.


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FACTOR TO BE CONSIDERED:

1. Well & reservoir characteristics

1. Well factor

• Well geometry, performance, especially PI, q

2. Reservoir factor• Reservoir properties especially drive & type

3. Fluid factor

• Fluid properties particularly GOR, composition, SG, viscosity

2. Field location & environment

• Well location & environment pollution

3. Operational problems

4. Economics

5. Implementation of artificial lift selection techniques

6. Long term reservoir performance & facility constraints

ARTIFICAL LIFT TECHNIQUE SELECTION CRITERIA


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1. Production casing size

2. Maximum size of production tubing & required production rate

3. Annular & tubing safety systems

4. Producing formation depth & deviation

5. Nature of produced fluids

6. Well inflow characteristics

WELL & RESERVOIR CHARACTERISTICS


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Influence of IPR on production increase achieved when welldrawdown increased

Influence of IPR on Production @ Drawdown Increased


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FIELD LOCATION & ENVIRONMENT

• Offshore platform design dictates maximum physical size and weight of

artificial lift equipment can be installed

• Onshore environment strongly influence artificial lift selection:

• Urban location requiring minimum visual & acoustic impact

• Remote location with minimum availability of support infrastructure or regular access to well

• Climatic extremes,

• e.g. arctic operations will limit practical choices

• Wellhead – processing facilities distance will determine minimum wellhead

flowing pressure

• E.g. ESP more attractive than gas lift since extra pressure drop @ flowline, due to injected

gas, makes gas lift unsuitable option

• Power source available for prime mover will impact detailed equipment

design & reliability

• E.g. voltage spikes reduce ESP’s electrical motor lifetime.


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OPERATIONAL PROBLEMS

• Sand production

gas lift more tolerant to solids than centrifugal pump

• Inhibitor can be carried in the power fluid for hydraulic pump -

suitable for massive organic & inorganic deposits such as paraffin, asphaltene, scale & hydrate


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ECONOMICS

• Full life cycle of economic analysis : operating cost vs initial capital cost to

installed artificial lift

• If capital cost to installed small as compared to total project costs and benefit to

increased revenue & reduced operating cost installed artificial lift

• Need to consider:

• Capital cost vs total operating cost & benefit

• Reliability (maintenance & operator costs)

• Energy efficiency

•Maintenance cost depend on: location, service company infrastructure

• Number of well (economic scale) operating costs

• Need for automation & centralised facilities operating costs

• Operational staff skill @ artificial lift technique


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Energy Efficiency of Various Artificial Lift Method

Energy Efficiency Comparison

Only ESP & PCP have EE > 50%


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IMPLEMENTATION

• Need to consider, how to:

• Determine the optimum type of artificial lift for a given well

• Matching facility constraints, artificial lift capabilities & well

productivity efficient lift installation ?

• Environmental factor

• Geographical factor

• Production problems: sand & paraffin production

• Reservoir fluid characteristics

Example:

• Populated area : sucker rod pump is not suitable

• GLR: suitable for gas lift but problem for all pumps


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Long Term Reservoir Performance

Problems in artificial lift selection & sizing 2 approaches

1. Equipment installed can handle well production & production condition @ lifetime

oversize equipment based on producing large water

equipment operate at poor efficiency due to underloading at early production

life

2. Design for current well producing conditions and not worry about future

many changes in type of lift equipment @ well’s producing life

low cost operation @ short term but large sums money spent later to change

artificial lift equipment and/or completion


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Facility Constraints

• In new field development; fluid handling equipment may significantly increase size &

cost of facilities required

– Rod pump & ESP : only produced fluid handled through facilities

– Gas lift requires injection gas compression & distribution facilities & circulating lift gas increases size of

production facilities required

– Hydraulic pump needs power fluid volume equal to produced fluid volume

• Wellbore size need to be consider for desired flow rate

– Casing designed to minimize drilling cost limitation on artificial lift equipment can be installed

– Smaller casing size higher long term production cost due to well servicing problems, gas separation

problems etc.


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1. Well factor – Big volume shallow well continuous flow gas lift, centrifugal pump, hydraulic pump

– Small volume shallow well sucker rod pump

– Small volume deviated deep well hydraulic pump

2. Reservoir factor – Water drive reservoir gas lift if adequate high pressure supply available

3. Fluid factor – High GOR Gas lift

– Crude with paraffin content Not suitable for hydraulic pump

– High viscosity & low gravity crude Not suitable for hydraulic pump

– High viscosity crude sucker rod pump

4. Environmental factor – To reduce pollution gas lift, hydraulic pump

– Offshore, remote area or wash land area less maintenance/treatment type, such asgas lift or hydraulic pump

METHOD/TYPE SELECTIONExamples


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Typical application areas ofartificial lift techniques


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• Oldest and most widely used for oil wells

• 4 principal parts:

– Pump

– Sucker rod string

– Pumping unit

– Prime mover

• Working principal: – As energy transmitted from prime mover to polished rod, speed reducer @ gear box

reduces the speed – Rotary motion translated to reciprocating motion through crank, pitman & beam

– Sucker rod string transmit horsepower from beam to pump – Downhole plunger moved up-down by a rod connected to engine @ surface – When pump actuated, work done on the well fluid as it is lifted to surface

– Plunger movement displaces produced fluid into tubing via pump (with travelling &standing valves within pump barrel)

– Moved up-down → fluid displaces → surface @ q

SUCKER ROD PUMP


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Surface Equipment @ Sucker Rod Pump

Sucker Rod Pump Surface Equipments


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Sucker Rod Operation

Sucker Rop Pump Operation


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• Advantages: – New wells, lower volume cost effective over time & simple

system & easier to operate. – Lifting moderate volume from shallow depth (1000 BPD @

7000 ft) – Lifting small volume from intermediate depth (200 BPD @14000 ft)

• Disadvantages:

– Most incompatible with deviated (doglegged) wells – Limited ability to produce sand-laden fluids – Paraffin & scale can interfere – Free gas interference can reduces pump efficiency – Leaking problems @ polished-rod stuffing box

SUCKER ROD PUMP

Advantages & Disadvantages


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1.Capital cost2.Downhole equipment3.Operating efficiency (hydraulic hp / input hp)

4.System Flexibility5.Miscellaneous Problems6.Operating costs7.System Reliability

8.Salvage Value9.System Total10.Usage/Outlook

ROD PUMPDESIGN CONSIDERATIONS


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– Capital cost• Low to moderate• Increases as depth and unit size increases

– Downhole equipment• Reasonably good rod design & operating practices needed• Data bank of failures beneficial

• Good selection, operating, and repair practices needed for rods & pumps

– Operating efficiency (hydraulic hp / input hp)• Excellent total system efficiency• With full pump fillage, efficiency typically 45 to 60%

– System Flexibility• Excellent

• Can alter strokes per minute, stroke length, plunger size & run time to controlproduction rate

– Miscellaneous Problems• Stuffing box leakage may be messy & potential hazard

ROD PUMPDESIGN CONSIDERATIONS


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– Operating costs• Low for shallow to medium depth (


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1. Casing Size Limits2. Depth Limits3. Intake Capabilities4. Noise Level

5. Obstrusiveness6. Prime Mover Flexibility7. Surveillance8. Relative Ease of Well Testing

9. Time Cycle & Pump Off

ROD PUMP

NORMAL OPERATING CONSIDERATIONS


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• Casing Size Limits – Problem in high rate well (required large plunger pump)

– Small casing sizes (4.5 – 5.5 in.) may limit free gas separation

• Depth Limits – Good

– Rod / structure may limit rate at depth – Effectively, 150 BPD at 15000 ft, 100 to 11000 ft typical, 16000 ft maximum

• Intake Capabilities – Excellent,


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• Prime Mover Flexibility – Good

– Both engine & motor can be used easily – Motor more reliable & fliexible

• Surveillance – Excellent – Can be easily analyzed @ well test, fluid level, etc

– Improved analysis by use of dynamometers & computer

• Relative Ease of Well Testing

– Good – Well testing simple with few problems with use of standard availableequipment & procedures

• Time Cycle & Pump Off – Excellent if well can be pumped off

ROD PUMP



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1. Corrosion/Scale Handling Ability2. Crooked/Deviated Holes3. Duals Applications4. Gas Handling Ability

5. Offshore Application6. Paraffin Handling Capability7. Slimhole Completions8. Solids/Sand Handling Ability9. Temperature Limitations

10.High Viscosity Fluid Handling Capability11.High Volume Lift Capability12.Low Volume Lift Capability

ROD PUMP

SPECIAL PROBLEMS & CONSIDERATIONS


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• Corrosion/Scale Handling Ability – Good to excellent

– Batch treating inhibitor down annulus feasible

• Crooked/Deviated Holes – Fair, increased load & wear problems

– High angle deviated holes (>70o) & horizontal wells are being produced

– Some success in 15o /100ft dogleg severity with use of rod guides

– Typical: 0 – 20, 0 – 90o,


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• Slimhole Completions – Feasible for low rates (


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Sucker Rod Pump Operational Diagnosis

• Pump conditions can be evaluated by measuring

load at top of polished rod as function of its

position dynamometer card recording

• Practical problems: – Excessive rod or pump friction

– Restriction in flow-path

– Vibrations

– Sticking plunger, leaking travelling or standing valves

– Gas presence in pump barrel and viscous emulsion

formation.


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Dynamic load experienced by properly operating pump


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• Use high pressure fluid to:

– Drive downhole turbine or positive pump, or

– Flow through venturi or jet, creating low pressurearea which produces increased drawdown andinflow from reservoir

• Two types: – Hydraulic jet pump

– Reciprocating positive displacement pump

HYDRAULIC PUMP


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Hydraulic Pump

Hydraulic Pump Completion


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Positive Displacement Hydraulic Pump Operation

Hydraulic Pump – Positive Displacement Pump


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Jet or Venturi Pump Operation

Jet or Venturi Pump Operation

• Venturi/nozzle -- reduced pressure pressure energy converted into velocity•High velocity low pressure flow of power fluid commingles with production flow @throat•Diffuser reduces velocity, increasing fluid pressure fluid flow to surface


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Hydraulic pump installation types:•Open system

• Power fluid supplied to downholeequipment via separate injection

tubing• Commingle exhaust fluid withproduction fluid

•Closed system• Power fluid supplied to downhole

equipment via separate injection

tubing• Power fluid return to surface via

third separate tubing


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HYDRAULIC PUMP CAPACITIES

RECIPROCATINGPOSITIVEDISPLACEMENTPUMP

RECIPROCATINGPOSITIVEDISPLACEMENTPUMP

JET-FREEPUMP

Tubing size (in.) Working Fluid Level (ft) Max.Pump Disp. (BPD) Production (BPD)

2 3/8 6000 - 17000 1311 - 381 3000

2 7/8 6000 - 17000 2500 - 744 6000

3 1/2 6000 - 15000 4015 - 1357 10000


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• Able to circulate the pump in and out of the well

• Positive-displacement pump capable of pumping depth to 17000 ft anddeeper for large volume

• Working fluid level of jet pump limited to 9000 ft

• By changing power-fluid rate to pump, production rate can be varied from10 – 100% of pump capacity. Optimum speed 20 – 85% of rated speed.Operating life significantly reduced if pump operated above the maximumrated speed

• Suitable for crooked & deviated wells

• Jet pumps, with hardened nozzle throats, can handle sand/solid• Positive displacement pump with diluents added or power fluid can be

heated, the pumps can handle viscous oils very well

• Corrosion inhibitors can be injected into power fluid for corrosion control. Added fresh water can solve salt-buildup problems

HYDRAULIC PUMP ADVANTAGES


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• Removing solid from power fluid is very important to positive-displacementpump. Solid can also affect surface plunger pump. But, jet pump verytolerant of poor power fluid quality

• Positive displacement pump have shorter life time than jet, sucker rod and

ESP but operating at greater depth and at higher strokes per minute thanbeam pump

• Jet pump have very long pump life, lower efficiency and higher energycosts

• Positive displacement pump can pump from low BHP (


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– Capital Cost• Varies, but often competitive with rod pumps

• Multiple well, central systems reduces cost per well but more complicated

– Downhole equipment• Proper pump sizing & operating practices essential

• Requires two conductors (power fluid & returns)

– Operating efficiency (hydraulic hp/input hp)

• Fair to good, usually not as good as rod pumping because of GLR, friction & pump wear)• Typical efficiency 30 – 40% with GLR>100, 40-50% if lower GLR

– System flexibility• Good to excellent

• Can vary power fluid rate; stroke / minute of downhole pump

• Numerous pump sizes & pump-to-engine ratio adapt to production & depth requirements

– Miscellaneous problems

• Power fluid solid control essential• 15 ppm of 15um particles maximum to avoid excessive engine wear

• Must add surfactant to water power fluid for lubricity

• High pressure power oil leakage may be hazardous

• Triplex plunger leakage control required

• Fluid system requires added tubing string

Hydraulic Reciprocating Pump

Design Considerations


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– Operating costs• Often higher than rod pump• Short run life increases total operating costs

– System Reliability• Good with correctly designed & operated system• Wellsite power fluid system minimizes power oil or water problems• Problems or changing well conditions reduce downhole pump reliability• Frequent downtime results from power oil problems, injection pressure, pump maintenance problems, & downhole

pump failure

– Salvage Value• Fair, some trade in value especially for triplex pump• Good value for wellsite system – easy moved well to well

– System Total• Simple manual / computer design well application• Operating procedures easily learned• Free pump retrieved for servicing• Individual well unit flexible but extra cost (requires attention)

• Central plant more complex; usually results in test & treatment problems – Usage/Outlook

• Often used as default artificial lift well system• Good for flexible operation; wide rate range to relatively deep, high volume, high temperature, deviated, oil wells• Used on


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– Capital Cost• Competitive with rod pump

• Relatively low cost over 1500 BFPD

• Increases with higher hp

– Downhole equipment• Requires computer design program for sizing

• Tolerant of moderate solid in power fluid

• No moving parts in pump; long service life, simple repair procedures to run & retrieve pumpdownhole

– Operating efficiency (hydraulic hp/input hp)• Fair to poor, maximum eff. (ideal) 30%

• Heavily influenced by power fluid & production gradient

• Typical operating eff. 10-30%

– System flexibility

• Good to excellent• Power fluid rate & pressure adjust production rate & lift capacity ( from no flow to full design

capacity installed pump)

• Selection of throat & nozzle sizes extends range of volume & capacity

– Miscellaneous problems• More tolerant of power fluid solid; 200 ppm of 25um particle acceptable

• Diluents may be added, if required

• Power water, either fresh, produced, or sea water is acceptable

Hydraulic Jet Pump



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– Operating costs• Higher power cost because of hp requirement

• Low pump maintenance cost with properly sized throat & nozzle for long run life

– System Reliability• Good with proper throat & nozzle sizing

• Must avoid operating in cavitation range of jet pump throat

• More problems if pressure >4000 psig

– Salvage Value• Good, easily moved well to well

• Fair, some trade in value (especially triplex pump)

– System Total• Available computer design program for application design

• Basic operating procedure for downhole pump & wellsite unit

• Free pump easily retrieved for on-site repair/replacement

• Downhole jet often requires trial & error to arrive at best/optimum jet – Usage/Outlook

• Good for higher volume wells requiring flexible operation, wide depth range, high temperature,high corrosion, high GOR, significant sand production

• Used on


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• Casing Size Limits – Large casing required for parallel free or closed systems – Small casing (4.5 – 5.5 in.) excessive friction losses & limits producing rate

• Depth Limits – Excellent but limited by power fluid pressure (5000 psi) or hp – Low volume/high lift pump operating at depths to 17000 ft.

– Typical depth: 7500 – 10000 ft, maximum 17000 ft• Intake Capabilities

– Fair, not as good as rod pumping – Pp


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• Prime Mover Flexibility – Excellent

– Can be electric motor, gas or diesel fired engines / motor

• Surveillance – Good/fair – Downhole pump performance can be analyzed from surface power fluid

rate & pressure, stroke/minute & producing rate – Pressure recorder can be run & retrieved on free pump

• Relative Ease of Well Testing – Fair and well testing with standard individual well units units present few

problems – Well testing with central system more complex; requires accurate power

fluid measurement

• Time Cycle & Pump Off – Poor but possible with electric drive wellsite unit

HYDRAULIC RECIPROCATING PUMP



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• Casing Size Limits – Small casing limits producing rate at acceptable pressure drop

– Larger casing required for dual strings

• Depth Limits

– Excellent & similar as reciprocating pump• Intake Capabilities

– Poor to fair; >350 psig to 5000 ft with low GLR

– Typical design target 25% submergence

• Noise Level – Same as reciprocating pump

• Obstrusiveness – Same as reciprocating pump

HYDRAULIC JET PUMP



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• Prime Mover Flexibility

– Same as reciprocating pump

• Surveillance


• Relative Ease of Well Testing


– Three stage production test can be conducted y adjustingproduction step rates

• Time Cycle & Pump Off

– Poor

HYDRAULIC JET PUMP



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• Corrosion/Scale Handling Ability – Good/excellent; batch/continuous treating inhibitor circulated downhole with power fluid

for effective control

• Crooked/Deviated Holes – Excellent; if tubing can be run in well & pump pass through tubing – Free pump retrieved without pulling tubing

• Duals Applications – Fair, limited to low GLR & moderate rate

• Gas Handling Ability – Good/fair

• Offshore Application – Fair, requires deck space for power fluid pump & preferably wellsite type power fluid

system to avoid increased production treating capacity – Power water may be used in closed power fluid system but power oil potential fire/safetyproblems

• Paraffin Handling Capability – Good/excellent. Heated power water/oil circulates heat to downhole pump to minimize

buildup – Hot water/oil treatment, mechanical cutting, inhibition possible

HYDRAULIC RECIPROCATING PUMP



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• Slimhole Completions – Possible but may have high friction losses / gas problems

– Have been used when moderate production rate & low GLR

• Solids/Sand Handling Ability – Poor; requires


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• Corrosion/Scale Handling Ability – Good/excellent; inhibitor with power fluid mixes with produced fluid at entry of jet pump

throat – Batch treat down annulus

• Crooked/Deviated Holes – Excellent; short jet pump can pass through doglegs up to 24 o /100ft in 2 3/8 in. tubing

– 0-20o typical; 0-90o


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• Slimhole Completions – Same as reciprocating pump except can handle higher GLR

• Solids/Sand Handling Ability – Fair/good; operating with 3% sand content – Power fluid can tolerate 200 ppm of 25um particle; freshwater treatment for salt buildup

possible

• Temperature Limitations – Excellent – Typical: 100-250oF, possible to operate @ 500-600oF with special material

• High Viscosity Fluid Handling Capability – Good/excellent; >6o API with 24o API & 15000 BPD maximum

• Low Volume Lift Capability – Fair; >200 BFPD from 4000 ft

HYDRAULIC JET PUMP



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• Employs downhole centrifugal pump driven by electric motorsupplied with electric power via cable run from surfacepenetrates wellhead & strapped to outside of tubing

• 5 basic components:

- Electric motor- Multistage centrifugal pump

- Electric cable (surface – pump)

- Switchboard

- Power transformer• Large volume : 150 – 60000 BPD

• Entire pumping system lowered, suspended on tubing string,to desired depth

ELECTRICAL SUBMERSIBLE PUMP (ESP)


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Electric Submersible Centrifugal Pump Well Completion

Electric Submersible Centrifugal Pump (ESP)


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ESP Completion Design with Gas Anchors

•Shroud :• to make use of casing ability to separate

produced gas from liquid• Increase maximum ESP diameter

•Suitable for low rate well with large annular clearances& large bubbles gas (free gas)•Protector or seal:

•Unit connects electric motor drive shaft topump or gas separator shaft

• Isolation barrier between clean motor oil & wellfluid

• Expansion buffer for motor oil• Equaliser for internal motor pressure & well

annular pressure• Absorber for thrust generated by pump

•Electric motor : 15 – 900 HP•Downhole sensor package: Measurement of:

• Pump suction & discharge P & T• Fluid intake T• Electric motor T• Motor & pump vibration• Electrical current leakage to earth


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ESP Incorporating Packer & @ Surface ControlledSubsurface Safety Valves

•Regulatory requirement• Venting gas to surface


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Typical ESP Applications

a. Direct water injection• Aquifer water lifted from

supply zone & pumpeddirectly to single injectionwell

b. Powered dumpflood with ESP• Water supply well

combine with injectionwell

• ESP inverted with pump atbottom & use to replaceconventional surfacemounted transfer pump

c. Pressure boosting surface pipelinewith shallow, subsurface mountedESP

• ESP use to boost pressurein surface flow line

d. Horizontally mounted ESP surfacepump


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Y-tool

•Device to allow wireline or CTaccess below ESP, including:

• Cased hole logging• Well stimulation• Perforating• Setting bridge plugs

(water shut off)• Pressure memory

gauges installation &recovery

• Plugs running &retrieval

• Downhole sampling

•Bypass tubing > 2.375”OD


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Pump Duty Requirements

•Pump required to deliverrequired pressure (TDH)• Total dynamic head (TDH)

• Difference between

pump discharge &suction pressure

• Sum of hydrostatic headfrom ESP pump tosurface, tubing pressurelosses

• Required surfacepressure @ q


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1. Basic dataCollect & analysis all well data (for design)

2. Production capacity

Determine well productivity @ pump setting depth or determine pump setting depth@ desired q

3. Gas calculationCalculate fluid volume @ pump intake conditions

4. Total dynamic head

Determine pump discharge requirement

5. Pump type

Given capacity @ head select pump type @ highest efficiency for q

6. Optimum size of components

7. Electric cable

8. Accessory & optional equipment

9. Variable speed pumping system

NINE STEPS - ESP


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1. Adaptable to highly deviated wells; up to horizontal but must be set in straight section.Crooked hole present no problem

2. Adaptable to required subsurface wellheads, 6 ft apart for maximum surface location density

3. Permit use of minimum space for subsurface controls & associated production facilities

4. Quiet, safe & sanitary for acceptance operation in offshore & environmentally consciousarea. Unobtrusive in urban locations

5. Generally considered a high volume pump. Can lift up to 20000BPD in shallow wells with

large casing. Available for different sizes, controllable production rate6. Provides for increased volumes & water cut by pressure maintenance & secondary recovery

operations

7. Permits placing wells on production even while drilling & working over wells in immediatevicinity

8. Simple to operate

9. Easy to install downhole pressure sensor for telemetering pressure to surface by cable

10. Corrosion & scale treatment easy to perform

11. Lifting cost for high volume generally very low

12. Efficient energy usage (>50% possible)

13. Access below ESP via Y tool

14. Comprehensive downhole measurements available

15. Quick start after shut down

ESP ADVANTAGES


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1. Pump susceptible to damage by producing solids tolerate minimal % sandproduction

2. Costly pulling operations and lost production when correcting downhole failures

3. Below 400 BPD, power efficiency drops sharply

4. Not suitable for low volume well ( 4.5 in OD) for moderate – high production rateequipment

6. Long life ESP equipment required to keep production economical.

7. Susceptible to damage during completion installation

8. Tubing has to be pulled to replace pump9. High GOR presents gas handling problems

10. Viscous crude reduces pump efficiency

11. High T can degrade electrical motors

12. Power cable requires penetration of wellhead & packer integrity

ESP DISADVANTAGES

ESP


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– Capital Cost• Relatively low if electrical power available• Increases as hp increases

– Downhole equipment• Requires proper cable in addition to motor, pump, seal, etc.• Good design & operating practices essential

– Operating efficiency (hydraulic hp/input hp)• Good for high rate wells but decreases significantly for


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– Operating costs• Varies. Higher hp high energy cost

• High pulling cost result from short run life especially in offshore operation

• Repair cost often high

– System Reliability• Varies. Poor for problem area (very sensitive to operating temperature & electrical malfunction)

– Salvage Value• Fair. Some trade in value. Poor open market value

– System Total• Fairly simple to design but requires good rate data.

• Requires excellent operating practices.

• Follow API RPs in design, testing & operation.

• Each well is individual producer with common electric system

– Usage/Outlook• Excellent high rate artificial system• Best suited for 1000BFPD rate

• Most often used on high water cut wells

• Used on 5% US lifted wells

ESP


ESP


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• Casing Size Limits – Will limit use of large motor & pump

– Avoid 4.5 in. casing & smaller

– Reduced performance inside 5.5 in. casing, depending on depth & rate

• Depth Limits

– Limited to motor hp or temperature – Practical depth 10000ft, typical 1000-10000ft TVD, 15000ft max.

• Intake Capabilities – Fair if little free gas (Pp > 250psi)

– 5% gas at low pressure can cause problems

• Noise Level

– Excellent. Very low noise. – Often preferred in urban area if production rate high

• Obstrusiveness – Good. Low profile but requires transformer bank

ESP


ESP


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• Prime Mover Flexibility – Fair.

– Requires good power source without spikes or interruption

– Higher voltage can reduce losses

• Surveillance – Fair. Electrical checks but special equipment needed otherwise

• Relative Ease of Well Testing – Good. Simple with few problems

– High water cut & high rate well may requires free water knockout

• Time Cycle & Pump Off – Poor.

– Soft start & improved seal/protectors recommended

ESP


ESP


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• Corrosion/Scale Handling Ability – Fair. Batch treating inhibitor down annulus feasible

• Crooked/Deviated Holes – Good. Few problems

– Limited experience in horizontal well. Requires long radius wellbore bends to getthrough

– 10o typical; 0-90o 5% through pump) – Rotary gas separator helpful if solid not produced

• Offshore Application – Good. Must provide electrical power & service pulling unit

• Paraffin Handling Capability – Fair. Hot water/oil treatments, mechanical cutting, batch inhibition possible

ESP


ESP


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• Slimhole Completions – Not record installed

• Solids/Sand Handling Ability – Poor. Requires


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ESP Ammeter Chart Monitoring

24 hours normal operation

•Technique:• Surface measurement of

current supplied to pumpalong with well test

• Supervisory Control &Data Acquisitionsystem(SCADA)



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Pumped off well

• At 8.15am: Pump started largeinitial current surge motor up tospeed•Motor speed increase & steadycurrent for next 3 hours withdecreasing slightly as fluid head abovepump decreases

• At 11.10am: current begins oscillaterapidly & increases until 1.15pm whenpump shut down•Suspected gas form problem whenPwf reduced below Pb gas locking &pump ceasing to pump.•Leaving well fluid level build up 100minutes & restart pump at 3.05pm•Same cycle repeated & problemsappear at 6.15pm•8.20pm: 3rd cycle started after 100minutes shut-in – current oscillationstarting again after 2 hoursproduction•11.00 pm : shut-in the well



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Pumped off well

•Basic problem : Pumping fluid to surface fasterthan fluid flowing into well from reservoir (outflow> inflow )•Continue stopping & restarting ESP motor is not

recommended due to damage to motor winding byinitial high current surge as motor begins to rotate

early motor burnout•Option are:

• Install lower capacity pump (smaller pump)• Operate pump at lower speed using variable

frequency drive (VFD)• Stimulate well to improve inflow performance

ESP Monitoring SCADA


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ESP Monitoring - SCADA

SCADA ESP M i i


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SCADA – ESP Monitoring

•Prior to energising pump, pump intake & discharge pressure same•Pump start at A

• Pump discharge pressure increasing• Motor T warmer than fluid entering pump

• Limited vibration @ surface choke adjustment•Follows by surface choke adjustment• At B steady operating conditions•Pump suction & discharge pressure slowly decline as well Pwfreduced

N T h l ESP


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New Technology ESP

• Coiled tubing deployed ESP

– Current: pump installed as part of conventional completion string & power cable

attached outside of tubing ESP as end of coiled tubing, power cable mounted

outside of coiled tubing & fluid flow inside of coiled tubing faster installation &

no need for wellhead penetration

• Auto “Y” tool

– Allow access below pump by flow generate power to open tool as compare to

wireline

• Dual pump installation

– Each zone having its own ESP & production tubing

• Reducing water production

– Hydrocyclone concept use for produced oil & water separation downhole

– Single electric motor powering upper & lower pump unit. Lower pump to operate

hydrocyclone & upper pump to lift up produced fluid


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• Employs helical, metal rotor rotating inside an elastometric,double helical stator

• Rotating action supplied by downhole electric motor or byrotating rods & prime mover

• Popular for viscous crude oil production

PROGRESSING CAVITY PUMP (PCP)


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Progressing Cavity Pump (PCP) Well Completion

Progressing Cavity Pump Completion


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PCP & Components (Cross Section View)

PCP Principle

a. Steel shaft rotor formed into helixb. Rotor rotated inside elastometric pump body or statorc. Offset center line of rotor & stator creating series if fluid filled cavities along the

length of pumpRotor within stator operates as pump fluid trapped in sealed cavities progress

along pump length from suction to discharge


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PCP – ADVANTAGES & DISADVANTAGES

Advantages Disadvantages

•Simple design

•High volume efficiency

•Efficient design for gas anchors available

•High energy efficiency

•Emulsion not formed due to low shear

pumping action

•Capable of pumping viscous crude oil•Can be run into horizontal & deviated

wells

•Q can be varied with variable speed

controller & cheap downhole pressure

sensor

•Moderate cost•High electrical efficiency

•High starting torque

•Fluid compatibility problems with

elastomers in direct contact with aromatic

crude oil

•Gas dissolves in elastomers, at high

bottom hole pressure

•Upper T limit for stator material

H2Schemical deterioration

•Frequent stops & starts several

operating problems (wear & leaking)

•Best efficiency occurs @ gas is separated

bottomhole separator needed

•If unit pump off the well or gas flowscontinuously, stator will be permanently

damaged (overheating by gas compression)

•Gearbox in ESPCP is source of failure if

wellbore fluid or solid leak inside it or if

excessive wear occurs

PCP


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– Capital Cost

• Low but increases as depth & pump rate increases

– Downhole equipment

• Problems on selection of stator elastomer

– Operating efficiency

• Excellent. May exceed rod pumps

• Typical: 40 – 70%

– System flexibility

• Fair, can alter strokes/minute

• Hydraulic unit provides additional flexibility with added cost – Miscellaneous problems

• Limited service in some areas with limited field knowledge & experiences

PCP


PCP


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– Operating costs

• Low but short run life on stator or rotor

– System Reliability

• Good. Normally over pumping & lack of experience decrease run time

– Salvage Value• Fair/poor.

• Easily moved & some market for used equipment

– System Total

• Simple to install & operate

• Each well as an individual system

– Usage/Outlook• Limited to relative shallow wells with low rate

• Used


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• Casing Size Limits

– Normally no problem for 4.5 in. casing & larger, but gas separationlimited

• Depth Limits

– Poor. Limited to shallow depth – Possible 5000ft, 2000-4000 ft typical, 6000ft TVD maximum

• Intake Capabilities

– Good.


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– Good. Both engines & motor can be used

• Surveillance

– Fair. Analysis based on production & fluid levels only• Relative Ease of Well Testing

– Good. Well testing simple with few problems

• Time Cycle & Pump Off

– Poor. Avoid shutdown in high viscosity/sand production


PCP


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• Corrosion/Scale Handling Ability

– Good. Batch treating inhibitor down annulus feasible

• Crooked/Deviated Holes

– Poor-fair. Increased load & water problems

– Very few known installation• Duals Applications

– No known installations

• Gas Handling Ability – Poor if pump must handle free gas

• Offshore Application – Poor. Need pulling unit

• Paraffin Handling Capability – Fair. Tubing may need treatment

– Rod scrapers not possible to use


PCP


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• Slimhole Completions

– Feasible if low rates, low GOR & shallow depth, but no known installation

• Solids/Sand Handling Ability

– Excellent. Up to 50% sand with high viscosity (>200cp) crude

– Decrease to 10% sand for water

• Temperature Limitations

– Fair. Limited to stator elastometer.

– Max. 250oF, typical 75-150oF

• High Viscosity Fluid Handling Capability – Excellent for high viscosity fluids provided no stator/rotator problems

• High Volume Lift Capability – Poor. Restricted to relatively small rate.

– Possible 2000 BFPD from 2000ft & 200 BFPD from 5000ft. Maximum 4500 BPD at shallow depth

• Low Volume Lift Capability – Excellent for


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• Require gearbox to reduce rotation speed sincecentrifugal pup in ESP is high speed device & PCP islow speed device

• Well suitable for handling solids & viscous fluid• Simple design & rugged construction – very reliable

• Low operating speed (300-600 rev/min) long

period downhole operation

• Problem of rotating rods & tubular in PCP PCESP

was introduced (PCP + ESP)

Progressing Cavity Electric Submersible Pump -

PCESP


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Comparison Between ESP & PCESP

ESP & PCESP Comparison

ROTATING ROD PUMP


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• Operates as electrical submergible centrifugalpump, but utilizes rotating rod as its means ofpower (not electrical cable)

• Internal combustion engine as its prime moveron the surface

• Generally utilized for shallow wells

ROTATING ROD PUMP

SONIC PUMP


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• Mechanical device actuated by conventional source ofpower

• Designed to vibrate tubing string so that series ofvalves, installed in tubing collar will lift fluid to surface

• Operates based on elastic characteristics of metalrod, free both ends that will vibrate according tosimple harmonic motion principle

• When tubing string vibrated at one end at a rate

corresponding to its fundamental frequency,vibrations transmitted over entire length of tubingstring and form standing wave on tubing (tubing is inresonance)

SONIC PUMP

PLUNGER LIFT


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• Plunger (free piston) fits inside tubing string andallowed to travel freely in the tubing string

• Provide sealing interface between liquid slugproduced by gas volume and gas volume itself

• Communication between tubing & casing willaccumulated a gas in casing-tubing annular spacebetween cycles (gas is a source power producingliquid slug)

• Plunger mechanically closed upon hitting bottom(provides positive seal for upward travel) and openedwhen at the top (provides bypass allowing plunger tofall back to bottom)

PLUNGER LIFT

Plunger Pump


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– Capital Cost• Very low if no compressor required

– Downhole equipment• Operating practices have to be tailored to each well for optimization• Some problems with sticking plungers

– Operating efficiency (hydraulic hp/input hp)• Excellent for flowing well. No input energy required because it uses

well energy

– System flexibility• Good to low volume well

• Can adjust injection time & frequency – Miscellaneous problems

• Plunger hang up & sticking is major problem


Plunger Pump


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– Operating costs• Usually very low unless plunger problem

– System Reliability

• Good if well production stable – Salvage Value

• Fair. Some trade in value• Poor open market value

– System Total• Individual well or system.

• Simple to design, install & operate

– Usage/Outlook• Essentially low liquid rate, high GLR lift method• Can be used for extending flow life or improving efficiency• Ample gas volume and/or pressure needed for successful

operation

• Used on


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• Casing Size Limits

– Small casing suitable for low volume type lift

• Depth Limits

– 8000ft TVD typical; 19000 ft TVD maximum• Intake Capabilities

– Good. Bottomhole pressure


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– None required

• Surveillance

– Good depending on good well tests & well pressure chart• Relative Ease of Well Testing

– Well testing simple with few problems

• Time Cycle & Pump Off – Not applicable


PLUNGER PUMP


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• Corrosion/Scale Handling Ability – Fair. Normal production cycle interrupted to batch treat the well

• Crooked/Deviated Holes – Excellent

• Duals Applications – No known installations

• Gas Handling Ability – Excellent

• Offshore Application

– Excellent for correct application• Paraffin Handling Capability – Excellent. Cuts paraffin & removes small scale deposits


PLUNGER PUMP


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• Slimhole Completions (2 7/8” production casing string) – Good. Similar to casing lift but must have adequate formation gas

• Solids/Sand Handling Ability – Sand can stick plunger. Plunger wipes tubing clean. Brush plunger

usually used for small amount of sand

• Temperature Limitations – Excellent

• High Viscosity Fluid Handling Capability – Not applicable

• High Volume Lift Capability – Poor. Limited by cycle number.

– Possible 200 BFPD from 10000ft. Typical 1 – 5 BPD; maximum 200-300BPD

• Low Volume Lift Capability – Excellent for 1-2 BFPD with high GLR


SELECTION METHODS


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1. Depth/Rate system capabilities consideration• Use of depth vs rate chart @ types can function

• Beam pump produces more from shallower depth & less from deeper depth• ESP can produce large production rate• Plunger for low liquid rate

• Initial selection possibilities or quick elimination of possibilities

2. Advantages & disadvantages

– Preliminary look of type operation details & capabilities3. Expert program available

– Computerized artificial lift selection programs, include rules & logic to select best system as functionof user input well & operating conditions

– Module 1: includes knowledge base structured from human expertise, theoretical, rule of thumb ranks selected types & issues warning

– Module 2: incorporates simulation design & facility-component specification programs for all selectedtypes

– Module 3: economic evaluation; cost database, cost-analysis program for lift profitability4. Net-present-value comparison

– More thorough selection technique depending on life time economics of available types; systemcomponents failure rate, fuel cost, maintenance cost, inflation rate, well anticipated revenue return

– Users required to have good idea on costs, advantages & disadvantages, additional equipment &costs,

SELECTION METHODS

ADVANTAGES


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Rod Pump ESP Venturi HydraulicPump Gas Lift PCP

•Simple, basic design

•Unit easily changed

•Simple to operate

•Can achieve low

BHFP

•Can lift high

temperature viscous

oils

•Pump off control –

pump motor off @

fluid level reached

minimum safety level

above the pump

•Extremely high

volume lift using up to

1000 kw motor

•Unobstrusive surfacelocation

•Downhole telemetry

available

•Tolerant high well

elevation / doglegs

•Corrosion / scale

treatments possible

•High volume

•Can use water as

power fluid

•Remote power source


deviation / doglegs

•Solids tolerant

•Large volume in high

PI wells

•Simple maintenance

•Unobstrusive surface

location / remote

power source


deviation / doglegs

•Tolerant high GOR

reservoir fluids

•Wireline maintenance

•Solids and viscous

crude tolerant

•Energy efficient

•Unobstrusive surface

location with

downhole motor

DISADVANTAGES


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Rod Pump ESP VenturiHydraulic Pump

Gas Lift PCP

•Friction in crooked

holes

•Pump wear with

solids production

•Free gas reduces

pump efficiency

•Obstrusive in urban

areas

•Downhole corrosion

inhibition difficult

•Heavy equipment for

offshore use

• Not suitable for

shallow, low volume

wells

•Full workover

required to change pump

•Cable susceptible to

damage during

installation with

tubing

•Cable deteriorates at

high temperature

•Gas and solids

intolerant

•Increased praduction

casing size often

•High surface

pressures

•Sensitive to change in

surface flowing

pressure

•Free gas reduces

pump efficiency

•Power oil systems

hazardous

•High minimum FBHP

•Abandonment

pressure may not be

reached

•Lift gas may not

available

• Not suitable for

viscous crude oil or

emulsions

•Susceptible to gas

FBHP

•Abandonment

pressure may not be

reached

•Casing must

withstand lift gas

pressure

•Elastomers swell in

some crude oils

•Pump off control

difficult

•Problems with

rotating rods (windup

& after spin) increase

with depth

HYBRID SYSTEMS


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• Combination of two artificial lift type

• Mostly combination of gas lift with other types (gas above )

• Some benefits of combining gas lift with positive displacement artificial lift

method (ESP, PCP, sucker rod, etc.)

– Increased volumetric efficiency –

higher liquid volumes – Decreased injection gas requirements compared to gas lift alone

– Increased reservoir drawdown & production

– Increase pump installation depth- allows greater reservoir drawdown

– Reduction in pump & motor power requirements – Lower electrical energy consumption compared to pump alone

– Gas lift provides backup in case of pump failure


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THANK YOU

Date post:	06-Jul-2018
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