artificial lift options

Section 1 Flow and Lift Processes

Flow and Lift Processes Introduction John Martinez 1

Introduction Producing the oil and gas from a well and from the reservoir is preceded by the exploration work, then drilling to test the structure, followed by completion procedures to set the tubulars and seal them with cement. Perforating opens a path for flow, and subsurface equipment guides the flow. The production rate obtained is the combined impact of reservoir delivery and wellbore plus flowline multiphase flow pressure change. When reservoir pressure declines or water fraction increases, the wells natural flow rate may be inadequate and artificial lift processes are implemented to increase or maintain rate. Artificial lift is a procedure to either:

1. Increase the gas-liquid ratio to maintain natural flow or 2. Transfer energy down-hole to pump the fluid and raise its pressure.

The six methods of artificial lift are illustrated in Figure 1.

Figure 1 - Artificial lift methods

OBJECTIVES

FLOW AND LIFT PROCESSES

LIST THE SIX FORMS OF ARTIFICIAL LIFT FREQUENTLY USED IN OIL PRODUCTION

IDENTIFY THE BASIC COMPONENTS OF EACH LIFT SYSTEM MATCH LIFT TYPES TO RESERVOIR AND PRODUCING CONDITIONS


Flow and Lift Processes Gas Lift John Martinez 2

Gas lift is the process of injecting gas into the tubing string to reduce the flowing fluid mixture density. The density reduction permits reservoir pressure to drive fluid to the surface facility. Pumping is the process of using electrical, mechanical, or hydraulic energy down-hole to drive a pump, which raises fluid pressure and drives it to the surface facility. Reservoir pressure drives fluid to the pump. The pump options are: Electric submersible pump Sucker rod pump Hydraulic positive displacement and jet pump Progressive cavity pump The questions to be resolved are: Which method? How does it work? What are the applications? The enabling mechanism or fluid to implement lift and operating considerations for each type are: Method Enabling Mechanism Operating Depth (TVD) Operating Volume*

(BPD) Gas lift High pressure gas To - 15,000 To - 30,000 Plunger Lift Reservoir pressure acting on

plunger To - 19,000 To - 50

Sucker rod pump

Mechanical rods To - 16,000 To - 5,000

Electric submersible pump

Electrical power cable To - 15,000 200 - 30,000

Progressive cavity pump

Mechanical rods To - 6,000 To - 4,500

Hydraulic jet pump

High pressure liquid To - 15,000 300 ->15,000

*The maximum operating volume decreases with increasing depth.

Gas Lift Gas lift is a natural flow process in that the reservoir pressure is the driving energy to push fluid to the wellbore, up to the wellhead, and into the surface facility. The wellbore, surface facility, and reservoir responses are the same for a natural flow well and for a gas lifted well. The purpose of gas lift? To reduce the density of the flowing mixture of gas, oil, and water by increasing the gas-liquid ratio with gas injection into the tubing through a gas lift valve or orifice. Best lift occurs when injection is at a deep point in the wellbore. Gas lift is best applied when one or more of these characteristics are present: Reservoir fluid has a high gas content Well has a good reservoir productivity (PI) Reservoir pressure can be maintained Fluid has entrained solids detrimental to pumps (reservoir fines, scale, paraffin, asphaltine, corrosion

products) Wellbore workover cost is high (offshore, international operations)



Gas lift gas (or nitrogen or CO2 circulation through coiled tubing) causes density reduction, which reduces flowing bottomhole pressure (Pwf). This benefit is attained by: Improving the gas to liquid ratio, supplementing reservoir gas Increasing the mixture velocity Changing the vapor-liquid distribution (flow pattern) to one with better mixing and reduced liquid

holdup Reducing wellhead back-pressure to promote gas expansion Gas lift is implemented by installing a system, Figure 2, that has the following components: High pressure compressor, dehydration,

and distribution pipeline(s) Gas measurement and control Injection of gas in the tubing-casing

annulus Gas lift valve and downhole mandrel(s)

on the tubing Low pressure production separator Gas return to compressor

Figure 2 - Gas lift system

The most frequently used gas lift valve is an injection pressure operated (IPO) valve. The valve has a closing pressure set by the nitrogen pressure (Pbt) inside the bellows. The pressure to keep the valve open is controlled by the injection (casing) gas pressure (Pg) applied to the outside of the bellows plus the multiphase (tubing) fluid pressure (Pf) below the port. Figure 3 shows the valve on a gas lift mandrel in the well and the pressure applied by the nitrogen, gas, and tubing fluid. The valve is a backpressure regulator and is set in the shop, at the calculated test rack opening (TRO) pressure, Pvo.

Figure 3 - Gas lift valve in well and in test rack



The schematic drawing of gas lift valves in a well are shown in Figure 4. The valves are in gas lift mandrels, which are attached to the tubing. For offshore wells, wireline retrievable valves are used. The upper valves are only used to unload the workover fluid, while a deeper valve is the operating (injection) point, which causes the gradient (density) change shown.

Figure 4 Gas lift schematic and pressure gradient graph The gas lift well in the field is identical to the natural flow well with the addition of the gas lift gas line to the tubing-casing annulus, Figure 5. The reservoir fluid and gas lift gas flow up the tubing, into the wellhead, and out the production flowline to the separator station.

Figure 5 - Gas lift wells in Texas (left) and the Middle East (right)


Flow and Lift Processes Plunger Lift John Martinez 5

Plunger Lift The plunger is shown Figure 6, and numerous options are available. The device rests on the bumper spring shown in illustration at right. The controller opens the well to flow, and the lubricator, catcher, and sensor on top of the existing wellhead retain the plunger when it surfaces. The controller timer shuts the well and releases the plunger, which falls to the bumper spring to start a new cycle, shown in the schematic at right.

Figure 6 Plungers (left) and well schematic (right)

Plunger Lift Well Plungers can be used to aid intermittent gas lift or to lift liquids accumulating in gas wells, Figure 7. The application in lift design is for relatively low liquid rates. The well is shut in with the surface wellhead control valve, as shown at left, and the liquid column builds in the tubing. The well is opened and the differential pressure drives the plunger to the wellhead catcher, causing a slug of liquid to be lifted above it. If gas lift gas is used intermittently, the slug size lifted can be a greater volume. The cycle of shut in, unloading of the slug with the plunger, and afterflow (mostly vapor with liquid mist) is repeated periodically, based on a field operators judgment of optimum time. Production testing to obtain rate versus cycle time is used determine the optimum.

Figure 7 Plungers equipment on well


Flow and Lift Processes Pumping Methods John Martinez 6

Pumping Methods Pumping is a different process than gas lift. For pumping, the reservoir pressure is the driving energy to push fluid to the pump suction intake, not to the surface. Using the energy transferred downhole, the pump then raises the fluid pressure to drive it up to the wellhead, and into the surface facility, Figure 8. The pumping advantage is that reservoir pressure can decline much lower than that for natural flow or for a gas lift well.

Figure 8 - Pump schematic and pressure gradient graph The purpose of pumping? To transfer energy down-hole to pump the fluid and raise its pressure. The selection is electrical, mechanical, or hydraulic energy transferred down-hole to drive a centrifugal, reciprocating, progressive-cavity (screw), or jet pump. Pumping is best applied when: Reservoir fluid has a low gas content Reservoir pressure is allowed to decline but gas does not increase No solids are in the reservoir fluid Wellbore workover cost is low (domestic operations onshore) Pump systems transfer the energy in a variety of methods: Electric submersible pumps use cable strapped to the tubing to power the submerged motor, which

drives the multistage centrifugal pump. An option is cable attached to the motor/pump assembly and suspended similar to wireline operations.

Sucker rod pumps use a rod string lifted by the surface beam pump to reciprocate the down-hole positive displacement pump.

Hydraulic jet pumps use pressurized crude oil or water from the surface high-pressure pumps to create a high velocity jet stream that has a venturi effect and inspirates reservoir fluid.

Hydraulic reciprocating pumps use pressurized crude oil or water from the surface high-pressure pumps to power a down-hole engine pump that is directly connected to the reservoir fluid reciprocating pump.

Progressive cavity pumps use the rod string and a motor driver at the surface to rotate the progressive cavity screw pump.



Electrical submergible pumping system surface facilities consist of: Generators or access to a power system and

power distribution high lines or cable Transformers and connectors to the wellhead The downhole electrical submergible components are: Electrical power cable in the annulus Electrical submersible motor Motor protector Centrifugal pump A manufacturers rendition of the electric submersible pump/motor assembly is given in Figure 9. The rate design for the pump must closely match reservoir delivery unless a variable frequency drive is used to alter motor speed and pump throughput.

Figure 9 - Electric submersible pump assembly The wellhead of the electric submersible pump system must have an electric cable entering. Figure 10 shows wells on a Thums Long Beach facility with deviated wellbores and close proximity wellheads. A special penetrator is used to conduct power through the wellhead and yet remain sealed to prevent leakage of reservoir fluids.

Figure 10 - Wellheads of submersible pump wells

MOTOR

PROTECTOR CABLE

PUMP



CONVENTIONAL

BEAM BALANCED

MARK II

AIR BALANCED

LOW PROFILE

PORTABLE

Sucker rod pumping system surface facilities consist of: Access to a power

system and electric motor to drive the surface beam pump, or a

Gas engine driver connected to the beam pump

The pumping components, Figure 11, are many but the primary items are: Beam pumping unit at

the surface Sucker rod string Downhole tubing pump

or insert rod pump

Figure 11 - Beam pump components

The beam pump, Figure 12, is the indicator of the sucker rod pump in the well. Also called a pump jack, the surface pumping unit lifts the

rod string, downhole pump, and fluid load. The beam pump is sized according to the fluid production rate and depth of lift.

Figure 12 - Beam pump (pump-jack)



The down-hole sucker rod pump is shown in Figure 13. The rods reciprocate the plunger inside the pump barrel. The two check ball valves serve to fill the barrel chamber (standing valve) and then let the fluid be displaced above the plunger and be pumped up to the surface (traveling valve). The lower standing valve opens during the up stroke (at left) when the barrel chamber pressure is less than the inflow pressure. The upper traveling valve (at right) opens during the down stroke when pressure in the chamber rises above the discharge pressure in the tubing above the plunger. If the fluid in the chamber is gassy, then it must be compressed before the traveling valve can open. This reciprocating pump is hampered by gas flashing at pump intake pressure and by solids in the fluid.

Figure 13 - Sucker rod tubing pump Hydraulic pumping uses a surface pump to pressurize produced water or crude oil, depending on which is readily available, to drive a downhole pump. The components are: Surface high pressure injection pump and

pipeline Injection tubing Downhole assembly to hold pump Positive displacement or jet pump (downhole) The reciprocating hydraulic pump uses the high pressure injection power fluid, red in Figure 14, to drive the engine pump, which in turn drives the reservoir fluid pump. Ball check valves and a double acting pump forces the reservoir fluid to the surface.

Figure 14 - Reciprocating hydraulic pump



The jet pump uses the high-pressure power fluid to create a high velocity venturi effect in the nozzle to throat gap (production inlet chamber) of the downhole pump, Figure 15. The low pressure induced in the gap causes reservoir production fluid to flow into the throat. The two fluids mix in the diffuser section, pressure recovery occurs, and the combined fluids flow back to the surface.

Figure 15 - Hydraulic jet pump components The hydraulic pump well has wellhead connections to the power fluid manifold, Figure 16. The return production line must carry the power fluid plus produced reservoir fluid, where the power fluid required can range from 1 to 3 barrels for each barrel of produced fluid.

Figure 16 - Hydraulic pumped well



Progressive cavity pumps use the principle of the screw and interference fit of the helix and the elastomer in the case to drive fluid to the surface, Figure 17. The helix is driven by rods from a surface motor, or directly connected to a submerged motor.

Figure 17 - Progressive cavity pump The surface drive motor for a progressive cavity pump is illustrated at left in Figure 18, and the starter and variable speed drive are at right. Sucker rods are used to transmit motion to the downhole pump, but the rods are rotated rather than reciprocated. Bottom drive with a submersible motor can also be done, which eliminates the rods.

Figure 18 - Progressive cavity pump and motor drive



The proper application of each lift type is related to the reservoir fluid, reservoir pressure, and production rate delivery as determined by inflow and multiphase outflow. Lift selection guidelines are:

GAS LIFT IS PREFERRED FOR

AN OFFSHORE WELL WITH HIGH WORKOVER COSTS WELLS THAT PRODUCE SAND OR OTHER SOLIDS HIGH PRODUCTION RATE, RESERVOIR PRODUCTIVITY AND PRESSURE HIGH GLR (GAS-LIQUID RATIO)

PUMPING IS PREFERRED FOR

AN ONSHORE WELL WITH LOW WORKOVER COSTS WELLS THAT PRODUCE CLEAN FLUIDS LOW GLR (GAS-LIQUID RATIO) SUBMERSIBLE PUMPS FOR: HIGH PRODUCTION RATE, RESERVOIR PRODUCTIVITY AND PRESSURE BEAM OR HYDRAULIC PUMPS FOR: LOW PRODUCTION RATE, RESERVOIR PRODUCTIVITY AND PRESSURE PROGRESSIVE CAVITY PUMPS FOR:

HEAVY OIL, SANDY FLUID, SHALLOW TO MODERATE DEPTH LIFT

OperatingDepthOperatingVolume (Typical)OperatingTemperatureCorrosionHandlingGasHandlingSolidsHandlingFluidGravityServicing

Prime Mover

OffshoreApplicationOverall SystemEfficiency

Rod Lift Progressing Cavity

Gas Lift PlungerLift

HydraulicPiston

HydraulicJet

To16,000 TVD

To 5000 BPD

100 -550 F

Good toExcellent

Fair toGoodFair toGood

>8 API

Workover orPulling RigGas Engine or Electric

Limited

45% - 60%

To 6,000 TVD

To 4,500 BPD

75-250 F

Fair

Fair

Excellent

8 API

Hydraulic orWireline

Gas Engine or Electric

Good

45% - 55%

To 15,000 TVD

300 - >15,000 BPD

100 -500 F

Excellent

Good

Good

>8 API



Excellent

10% - 30%

To 15,000 TVD

To 30,000 BPD

100 -400 F

Excellent

Good

>15 API

Wireline orWorkover Rig

Compressor

Excellent

10% - 30%

To 19,000 TVD

To 50 BPD

120 -500 F

Excellent

Excellent

Poor toFair

WellheadCatcher or Wireline

Wells Natural Energy

N/A

N/A

ElectricMotor

100 -400 F

Good

Poor to FairPoor

to Fair

>10 API

Workover orPulling Rig

Excellent

35% - 60%

To 15,000 TVD

200 - 30,000 BPD

Good toExcellent

ElectricSubmersible

GLR Required -300 SCF/BBL/1000 Depth

OperatingDepthOperatingVolume (Typical)OperatingTemperatureCorrosionHandlingGasHandlingSolidsHandlingFluidGravityServicing

Prime Mover

OffshoreApplicationOverall SystemEfficiency

Rod Lift Progressing Cavity

Gas Lift PlungerLift

HydraulicPiston

HydraulicJet

To16,000 TVD

To 5000 BPD

100 -550 F

Good toExcellent

Fair toGoodFair toGood

>8 API

Workover orPulling RigGas Engine or Electric

Limited

45% - 60%

To 6,000 TVD

To 4,500 BPD

75-250 F

Fair

Fair

Excellent

8 API



Good

45% - 55%

To 15,000 TVD

300 - >15,000 BPD

100 -500 F

Excellent

Good

Good

>8 API



Excellent

10% - 30%

To 15,000 TVD

To 30,000 BPD

100 -400 F

Excellent

Good

>15 API

Wireline orWorkover Rig

Compressor

Excellent

10% - 30%

To 19,000 TVD

To 50 BPD

120 -500 F

Excellent

Excellent

Poor toFair

WellheadCatcher or Wireline

Wells Natural Energy

N/A

N/A

ElectricMotor

100 -400 F

Good

Poor to FairPoor

to Fair

>10 API

Workover orPulling Rig

Excellent

35% - 60%

To 15,000 TVD

200 - 30,000 BPD

Good toExcellent

ElectricSubmersible

GLR Required -300 SCF/BBL/1000 Depth



SUMMARY FLOW AND LIFT PROCESSES

GAS LIFT IS AN EXTENSION OF NATURAL FLOW PUMPING USES ENERGY DOWN-HOLE TO RAISE FLUID PRESSURE CHOICE BASED ON RATE, RESERVOIR, AND COST CONDITIONS

artificial lift options

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