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Type of artificial lift system - Coggle Diagram
Type of artificial lift system
GAS LIFT
ADVANTAGES
• Downhole equipment initial cost is low
• Long service life
• Low sub-surface equipment maintenance
• Can be utilized for high or low production rate wells
• Fairly flexible over a wide range of producing conditions
• Power source can be remotely located
• Able to lift gassy wells
• Applicable to vertical and angled well
• Especially applicable for offshore used
• Gas lift valves is unaffected by produced solids
• Relatively simple completion
• Independent of BHT
DISADVANTAGES
• High initial cost for surface facilities
• Unavailability of continuous gas supply
• Inefficient for small fields (high ratio of cost to profit)
• Difficult to lift emulsion and viscous crude
• Gas freezing and hydrate problems
• Requires technical experts (skilled operators)
• Unable to effectively produce deep wells to abandonment
• Casing must be designed to withstand lift pressure
• Safety hazard with high pressure gas
MECHANISM
• Gas lift is implemented in lifting fluid where a relatively high pressure gas (> 250 psi) from the external source is used as lifting medium through mechanical process by continuous or intermittent flow (lifting fluid by injection of gas into the well).
• Injection of gas lifts fluid through several effect:
• Reduced load/weight of fluid column above the injection point.
• Injected gas expansion
• Fluid displacement
Combination: coalescence of gas bubbles into gas slug which capable of displacing liquid slug (slug flow)
Hydraulic pump
MECHANIS
• Use high pressure fluid to:
Drive downhole turbine or positive pump
Flow through venturi or jet, creating low pressure area which produces increased drawdown and inflow from reservoir
• Venturi/nozzle – reduced pressure and pressure energy converted into velocity
• High velocity low pressure flow of power fluid commingles with production flow at throat
• Diffuser reduces velocity, increasing fluid pressure allowing flow to the surface
ADVANTAGES
• Able to circulate the pump in and out of the well
• Positive displacement pump is capable of pumping at depth up to 17000 ft and deeper for large volume (lower rate)
• Working fluid level of jet pump is limited to 9000 ft
• By changing power fluid rate to pump, production rate can be varied from 10-100% of pump capacity. Optimum speed however is limited to 20-85% of rated speed. Operating above the maximum rated speed may reduce the life expectancy of pump.
• Suitable for crooked or deviated wells.
• Jet pumps, with hardened nozzle throats can handle solid/sand
• 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 build-up problems.
DISADVANTAGES
• Removing solid from power fluid is very important to positive displacement pump.
Solid can also affect surface plunger pump. But jet pump is very tolerant 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 min than sucker rod pump.
• Jet pump have a very long pump life, lower efficiency and higher energy costs.
• Positive displacement pump can pump from low BHP (< 100 psi). Jet pump requires at least 1000 psi BHP if set at 10000 ft and 500 psi when set at 5000 ft
• Positive displacement pump generally requires more maintenance than jet pump and other artificial lift (pump speed must be monitored daily to be within the allowable rated speed)
Electrical submersible pump (ESP)
MECHANISM
-Employs downhole centrifugal pump driven by electric motor supplied with electric power via cable from the surface strapped outside the tubing.
-Entire pumping system lowered, suspended on tubing string to the desired depth
• Adaptable to highly deviated wells up to horizontal but must be set in straight section. Crooked hole present no problem.
• Adaptable to required subsurface wellheads, 6 ft apart for maximum surface location density,
• Permit use minimum space for subsurface controls and associated production facilities
• Generally considered a high volume pump. Can lift up to 20000 BPD in shallow wells with large casing. Available for different sizes, controllable production rate
• Provides for increased volumes and water cut by pressure maintenance and secondary recovery operations
• Permits placing wells on production even while drilling and working over wells in immediate vicinity
• Simple to operate
• Easy to install downhole pressure sensor for telemetering pressure to surface by cable
• Lifting cost for high volume generally very low
• Efficient energy usage (>50% possible)
• Access below ESP via Y-tool
• Comprehensive downhole measurements available
• Quick start after shut-down
DISADVANTAGES
• Pump susceptible to damage by producing solids: tolerate minimal % sand production
• Costly pulling operations and lost production when correcting downhole failures
• Below 400 BPD, power efficiency drops sharply
• Not suitable for low volume well (< 150 BPD)
• Need relatively large casing size (> 4.5 in OD) for moderate to high production rate equipment
• Long life ESP equipment required to keep production economical
• Susceptible to damage during the completion installation
• Tubing has to be pulled to replace pump
• High GOR presents gas handling problems
• Viscous crude reduces pump efficiency
• High T can degrade electrical motors
• Power cable requires penetration of wellhead and packer integrity.
Plunger lift
MECHANISM
• Plunger (free piston) fits inside tubing string and allowed to travel freely in the tubing string
• Provide sealing interface between liquid slug produced and gas volume
• Communication between tubing and casing will accumulated a gas in casing-tubing annular space between cycles (gas is a source power in producing liquid slug)
• Plunger mechanically closed upon hitting bottom (provides positive seal for upward travel) and opened when at the top (provides bypass allowing plunger to fall back to the bottom)
Progressive cavity pump
MECHANISM
• Steel shaft rotor formed into helix
• Rotor rotated inside elastometric pup body or stator
• Offset center line of rotor and stator, creating series if fluid filled cavities along the length of pump
• Rotor within stator operates as pump where fluid trapped in sealed cavities progress along pump length from suction to discharge
• Employs helical, metal rotor rotating inside and elastometric, double helical stator.
• Rotating action supplied by downhole electric motor or by rotating rods and prime mover.
ADVANTAGES
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 and deviated wells
Q can be varied with variable speed controller and cheap downhole pressure sensor
Moderate cost
High electrical efficiency
DISADVANTAGES
High starting torque
Fluid compatibility problems. Elastomers in direct contact with aromatic crude (benzene)
Gas dissolves in elastomers at high bottomhole pressure
Upper T limit for stator material, hydrogen sulfide chemical deterioration
Frequent stops and starts, several operating problems (wear and leaking)
Best efficiency occurs when gas is separated therefore requires bottomhole separator
If unit pump off the well or gas flows continuously, stator will be permanently damaged (overheating by gas compression)
Sucker road pump
MECHANIS
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 and beam
Sucker rod string transmit horsepower from beam to pump
Downhole plunger moved up-down by a rod connected to engine at surface
Plunger movement displaces produced fluid into tubing via pump (with travelling and standing valves within pump barrel)
Moved up and down displacing fluid to the surfaces at certain flow rate.
ADVANTAGES
Efficient for new wells with lower volume: Cost effective over time and simple system and 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 wells
Limited ability to produce sand-laden fluids
Paraffin and scale can interfere
Free gas interference can reduces pump efficiency
Leaking problems @ polished-rod stuffing box