introduction to artificial lift - active...
TRANSCRIPT
As covered in the following modules:
Gas Lift and ESP Pump Core
Rod, PCP, Jet Pumps, and Plunger Lift Core
Introduction to Artificial Lift Methods
Learning Objectives
This section will cover the following learning objectives:
Identify the most common artificial lift technologies employed bypetroleum engineering operations to exploit and maximizehydrocarbon recovery
Understand how and why wells, which initially produce undernaturally flowing conditions, must ultimately be mechanicallyassisted to produce major volumes of remaining reserves
Recognize the engineering design and operationscharacteristics of: beam pump systems, gas lift systems,electrical submersible pump systems, progressing cavity pumpsystems, and plunger lift systems
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Well Pressure Terminology
Pres – reservoir pressure
Pwf Pres
Psep
Pftp
Pwf – flowing bottom hole pressure(wf - well flowing)
Pftp – surface pressure(ftp - flowing tubing pressure)
Psep – separator inlet pressure
(Pres - Pwf) is referred to as “drawdown”
Nodal Analysis principles illustrate how flow from the reservoir to the well is observed, measured, and managed by various test methods.
The data above illustrates one method to quantify how reservoir energy provides flow rate into a well as a f(Pres - Pwf).
From Nodal AnalysisTM
Pwf
Pres
Qliquids
Call this data the “Inflow” representing
Well “A”for a well on natural flow
Pres - Pwf or “drawdown”to create flow rate “Q” into the well
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The data below illustrates another method to quantify how reservoir energy provides flow rate to a well as a f(Pres - Pwf).
From Nodal AnalysisTM
Pwf
Pres
Qliquids
Call this data the “Inflow” representing Well “B”
for a well on natural flow
What is different?
Well “B”• Pressure at Pwf is above
bubble point pressure • Inflow curve is a straight
line
Well “A”• Pressure at Pwf is below
bubble point pressure • Inflow curve is a curved
line
From Nodal AnalysisTM
Pwf Pwf
Two different cases, “A” & “B”, based upon conditions at the chosen node Pwf
with regard to fluid Bubble Point pressure
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Nodal Analysis principles also illustrate how flow to the surface in tubing is observed, measured, and managed.
The curve above illustrates a specific size of tubing and the bottom hole pressure (Pwf) under specific conditions.
From Nodal AnalysisTM
Pwf
Pres
Qliquids
… tubing data for outflow
From Nodal AnalysisTM
To create the tubing curve, or Outflow data, Pwf is the pressure at the base of the tubing string that is available to deliver all of the reservoir fluids—oil, gas, condensate, and water—to the surface and possibly through the choke and flowline to the separator.
Pwf is also simultaneously working with the reservoir to create the Inflow curve.
Pwf Pres
Psep
Pftp
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Pwf
Pres
Qliquids
From Nodal AnalysisTM
Combining the reservoir and tubing pressure requirements of a producing zone establishes a “well performance” or nodal analysis model. Another term for nodal analysis is “system analysis.”
Thus, for a specific amount of reservoir energy and specific tubing size, an equilibrium for rate Q and Pwf results.
…for a well on natural flow
Q
From Nodal AnalysisTM
Artificial Lift provides the opportunity to recover remaining reserves when there is no further intersection of well inflow performance and tubing string performance curves.
Reservoir energy has depleted and the capacity of the tubing in place is too great for the remaining reservoir energy.
Pwf
Pres
Qliquids
… for a well no longer capable of natural flow
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Artificial Lift provides the opportunity to recover remaining reserves when there is no further intersection of well inflow performance and tubing string performance curves.
Pwf
Pres
Qliquids
For a gas well where reservoir pressure has dropped and water
invasion has occurred…
From Nodal AnalysisTM
…the identical parallel story for gas reservoir depletion
will also be presented.
Reservoir energy has depleted and the capacity of the tubing in place is too great for the remaining reservoir energy.
Artificial Lift Type Selection
So, what is the best process for selecting the most appropriate artificial lift completion type for an oil reservoir well?
And, how can gas wells be dewatered after the remaining energy from a gas reservoir is mostly depleted?
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Artificial Lift Type Selection – “Defining the Need”
How is artificial lift selection conducted?
Careful consideration of current and future well conditions is necessary
Many rules-of-thumb exist and many options to analyze
There is no single technique that provides a quick and easy answer
Pre-Planning Data and Engineering Considerations• Anticipated well production rate
over time (inflow)• Anticipated well / zone life• Anticipated GOR / GLR over life• Anticipated water cut over life• Well / zone depth• Temperature gradient• Casing / tubing restrictions• Hole geometry / deviation• Power availability (electricity, lift
gas, fuel gas, power fluid, etc.)• Sand production • Scale tendencies, asphaltenes,
paraffins• Offshore or onshore• Costs• Other
Company “A” Oil Production From A/L
• ESP 49%• BP 32%• PCP 8%• Gas Lift 4%• Plunger 3% (gas wells de-watered)• Hydraulic 2%• Other 4%
Three Examples of Artificial Lift Type Variance by Company
Company “A” Oil Production From A/L
• ESP 49%• BP 32%• PCP 8%• Gas Lift 4%• Plunger 3% (gas wells de-watered)• Hydraulic 2%• Other 4%
Company “B” Oil Production From A/L
• Gas Lift 65%• BP 20%• ESP 13%• Jet, Hydraulic Pump & PCP < 2%
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Three Examples of Artificial Lift Type Variance by Company
Company “C”
Oil Production From A/L• Beam Pumps 82%• Gas Lift 10%
• ESP 4%
• Hydraulic 2%• Other 2%
These three examples reflect the different reservoir and operating conditions that govern the optimum selection of artificial lift completion type.
Though these individual company artificial lift requirements vary significantly, the greatest number of wells on artificial lift worldwide by far employ beam pump completions.
Note the broad difference in AL types installed
Electronic Controller
DriveHead
Low rates Heavy oilSome sandLow gas
High ratesGas supplyOffshore production
Gas well dewateringFinal depletionVery low cost
Heavy oilSome sandLow gasHigh viscosity
Power fluidTemp testsHigh cost
SelectionGuide
Very high rates No sand, Low gasPower source
Major Types of Artificial Lift Illustrated
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Beam Lift
(Rod Pump)Progressing Cavity Gas Lift Plunger Lift Hydraulic Piston Hydraulic Jet
Electric
Submersible
Operating Depth (feet) 100‐ 16,000 2,000‐6,600 5,000 ‐ 15,000 8,000 7,500‐17,000 5,000‐15,000 1,000‐15,000
Operating Volume (Typical, bpd) 5‐5,000 5‐4,500 200‐30,000 1‐5 50‐4,000 300 ‐15,000 200‐30,000
Operating Temperature (F) 100‐550 75‐250 100‐400 500 100‐500 100‐500 100‐400
Corrosion Handling Good to Excellent Fair Good to Excellent Excellent Good Excellent Good
Gas Handling Fair to Good Good Excellent Excellent Fair Good Poor to Fair
Solids Handling Fair to Good Excellent Good Fair Poor Good Poor to Fair
Fluid Gravity (API) >8 >35 >15GLR Required 300
SCF/BBL>8 >8 >10
ServicingWorkover or
Pulling Rig
Workover or
Pulling Rig
Wireline or
Workover Rig
Wellhead Catcher
or Wireline
Hydraulic or
Wireline
Hydraulic or
Wireline
Workover or
Pulling Rig
Prime MoverIC Engine or
Electric Motor
IC Engine or
Electric Motor
IC Engine or
Electric Motor
Well's Natural
Energy
IC Engine or
Electric Motor
IC Engine or
Electric MotorElectric Motor
Other RequirementsFuel Gas or
Electrical Power
Fuel Gas or
Electrical Power
Natural Gas &
Compressor
Solar or Electrical
Power for
Controller
Fuel Gas or
Electrical Power
Crude or Water;
Fuel Gas or
Electrical Power
Electrical Power
Offshore Application Limited Good (for N/A Good Excellent Excellent
Overall System Efficiency 45%‐60% 40%‐70% 10%‐30% N/A 45%‐55% 10%‐30% 35%‐60%
Operating Depth (feet)
Operating Volume (Typical, bpd)
Operating Temperature (F)
Corrosion Handling
Gas Handling
Solids Handling
Fluid Gravity (API)
Servicing
Prime Mover
Other Requirements
Offshore Application
Overall System Efficiency
Beam Lift (Rod Pump)
Progressing Cavity Gas Lift Plunger Lift
Hydraulic Piston
Hydraulic JetElectric
Submersible
Good
< 35
Artificial Lift System Application Matrix
(30.5–4876.9 m) (609.6–2011.7 m) (30.5–4876.9 m) (30.5–4876.9 m) (30.5–4876.9 m) (30.5–4876.9 m) (30.5–4876.9 m)
(0.8–794.9 m3/D) (0.8–715.4 m3/D) (31.8–4770 m3/D) (0.16–0.8m3/D) (7.9–635.9 m3/D) (47.7–2385 m3/D) (31.8–4770 m3/D)
(37.8–287.8ºC) (23.9–121.1ºC) (37.8–204.4ºC) (260ºC) (37.8–260ºC) (37.8–260ºC) (37.8–204.4ºC)
(53.43 m3/m3)
Artificial Lift Selection: An Elimination Process
Higher Volume
Hydraulic Jet Pumps
Electric Submersible
Pump
Gas Lift
(m3 /
Day
)
(794.9)
(1590)
(2385)
(3180)
(3975)
(4770)
(5565)
Vertical Lift Depth ft (m)
(30
4.8
)
(60
9.6
)
(91
4.4
)
(121
9.2)
(152
4)
(182
8.8)
(213
3.6)
(243
8.4)
(274
3.2)
(304
8)
(335
2.8)
(365
7.6)
(396
2.4)
(426
7.2)
(457
2)
(487
6.8)
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GHTPDF of the matrix is available for download in the list of resources in the PetroAcademy activity.
Artificial Lift Selection: An Elimination Process
Lower Volume
Plunger Lift
Progressive Cavity Pumps
Beam (Rod) Pumps
Reciprocating Hydraulic Pumps
(79.5)
(159)
(238.5)
(318)
(397.5)
(477)
(556.5)
(635.9)
(715.4)
(m3 /
Day
)
( 30
4.8
)
(60
9.6
)
(91
4.4
)
(121
9.2)
(152
4)
(182
8.8)
(213
3.6)
(243
8.4)
(274
3.2)
(304
8)
(335
2.8)
(365
7.6)
(396
2.4)
(426
7.2)
(457
2)
(487
6.8)
Vertical Lift Depth ft (m)
Well: An offshore well has the following data available. What artificial lift system is the best choice? Why? What is missing from the data and the matrix below which would further guide selection?
Data: 10,000' (3048 m) TVD, 950 bfpd (151.04 m3/D)(oil and water), 12% w.c., 200oF (93.3oC) bottom hole temperature, trace H2S, high salinity formation water, 1000 scf/stb (178.1 m3/m3) GLR, minimal sand production, 32o API, company workover rigs and pulling unit rigs available; electricity available, gas supply available long term, reservoir drive mechanisms well understood.
Beam Lift
(Rod Pump)Progressing Cavity Gas Lift Plunger Lift Hydraulic Piston Hydraulic Jet Electric Submersible
Operating Depth (feet) 100‐ 16,000 2,000‐6,600 5,000 ‐ 15,000 8,000 7,500‐17,000 5,000‐15,000 1,000‐15,000
Operating Volume (Typical, bpd) 5‐5,000 5‐4,500 200‐30,000 <100 50‐4,000 300 ‐15,000 200‐30,000
Operating Temperature (F) 100‐550 75‐250 100‐400 1‐5 100‐500 100‐500 100‐400
Corrosion Handling Good to Excellent Fair Good to Excellent Excellent Good Excellent Good
Gas Handling Fair to Good Good Excellent Excellent Fair Good Poor to Fair
Solids Handling Fair to Good Excellent Good Fair Poor Good Poor to Fair
Fluid Gravity (API) >8 >35 >15GLR Required 300
SCF/BBL>8 >8 >10
ServicingWorkover or Pulling
Rig
Workover or Pulling
Rig
Wireline or
Workover Rig
Wellhead Catcher or
Wireline
Hydraulic or
Wireline
Hydraulic or
Wireline
Workover or Pulling
Rig
Prime MoverIC Engine or Electric
Motor
IC Engine or Electric
Motor
IC Engine or Electric
Motor
Well's Natural
Energy
IC Engine or Electric
Motor
IC Engine or Electric
MotorElectric Motor
Other RequirementsFuel Gas or Electrical
Power
Fuel Gas or Electrical
Power
Natural Gas &
Compressor
Solar or Electrical
Power for Controller
Fuel Gas or Electrical
Power
Crude or Water; Fuel
Gas or Electrical
Power: Power Fluid
System
Electrical Power
Offshore Application Limited Good Good N/A Good Excellent Excellent
Overall System Efficiency 45%‐60% 40%‐70% 10%‐30% N/A 45%‐55% 10%‐30% 35%‐60%
< 35
Artificial Lift Selection: Example
(37.8–287.8ºC) (609.6–2011.7 m) (30.5–4876.9 m) (30.5–4876.9 m) (30.5–4876.9 m) (30.5–4876.9 m) (30.5–4876.9 m)
(0.8–794.9 m3/D) (0.8–715.4 m3/D) (31.8–4770 m3/D) <15.9 m3/D) (7.9–635.9 m3/D) (47.7–2385 m3/D) (31.8–4770 m3/D)
(37.8–287.8ºC) (23.9–121.1ºC) (37.8–204.4ºC) (37.8–260ºC) (37.8–260ºC) (37.8–204.4ºC)(-17.2–-15ºC)
(53.43 m3/m3)
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PDF of the matrix is
available for download in the list of resources
in the PetroAcademy
activity.
Learning Objectives
This section has covered the following learning objectives:
Identify the most common artificial lift technologies employed bypetroleum engineering operations to exploit and maximizehydrocarbon recovery
Understand how and why wells, which initially produce undernaturally flowing conditions, must ultimately be mechanicallyassisted to produce major volumes of remaining reserves
Recognize the engineering design and operationscharacteristics of: beam (rod) pump systems, gas lift systems,electrical submersible pump systems, progressing cavity pumpsystems, and plunger lift systems
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Why This Module Is Important
Proper artificial lift selection, design, implementation, and operation for producing well completions are critical factors in achieving both optimum production rate control over time
Gas lift candidate wells require specific conditions to be in place for engineering selection of gas lift as the artificial lift method of choice
ESP candidate wells require a different set of specific conditions to be in place
Engineers must evaluate each reservoir’s fluids, lithology, and well completion characteristics to arrive at the proper selection of artificial lift type for each well requiring artificial lift
It is possible that a single well may require different types of artificial lift systems over the completion life of a well based upon changing well conditions
Why This Module Is Important
Properties/Characteristics/
FeaturesWell A Well B
Production Rate High Very High
Gas/Liquid Ratio High Low
Zonal Gas Production Moderate Low
Well Geometry
Moderate Deviation
Some Deviation
Location Offshore Onshore
Water Cut High Very High
An example of why an engineer must study well conditions carefully is provided below:
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Gas Lift
Gas Lift and ESP Pump Core
Learning Objectives
By the end of this lesson, you will be able to:
Understand the concept of gas lift in both unloading mode andoperating mode to start up a gas lift completion and operate thecompletion over its life
Identify the principles of gas lift valve performance and theproper location of the operating valve and unloading valves
Recognize the characteristics of lift gas performance analysis toproperly establish the most efficient gas lift completionperformance conditions
This section will cover the following learning objectives:
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Gas Lift
Gas lift works byinjection of highpressure gas intothe well’s casing /tubing annulus
Gas injected intothe casingannulus entersthe tubing andlightens the liquidgradient in thetubing up to thesurface
PFBH SIBHP
Pressure
De
pth
Gas injected into casing annulus
Gas lift valves
Gas Lift
There are two types of gas lift:
PBHP SIBHP
When gas is continuously injected, this artificial lift method is referred to as continuous gas lift
It is the most common type of gas lift completion
Pressure
De
pth
Gas lift valve
Gas in casing
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Pressure
De
pth
SBHP
Gas Lift
Much less common is intermittent gas lift
Gas is injected periodically at a high rate
Lifting effect is created by displacing slugs of liquid in a piston effect to the surface
There are two types of gas lift:
Gas Lift Valve Operation
View the mechanicaldevices required for gas lift
Gas will enter the tubingthrough gas lift valves
These valves are installed ingas lift mandrels and atypical well might have 5-10gas lift mandrels
Gas lift mandrels
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Gas Lift Valve Operation
Typical gas lift mandrel
Gas lift valve
Orienting sleeve allows pulling and setting valves
in deviated wells Guard protects valve latch neck against large tools and coiled tubing, snubbing strings, etc.
Thru-bore ID as large as tubing drift
Valve pocket with polished seals areas
for valve pack-off
Gas Lift Valve Operation
Gas lift valve itself sitsinside the mandrel pocket
Mandrel pocket
Gas exits through holes in the valve nose
Packing
PackingOperation
Gas from the casing enters the area between the seals
through holes in the mandrel and pocketGas enters through
holes in the valve
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Gas Lift Valve Operation
Important valve parts
Dome area which holds nitrogen pressure charge
Valve bellows grow in length with internal pressure
Valve seat
Valve choke
Check valve seats when fluid velocity is in upward direction
Gas exits through holes in the valve nose
Valve stem with ball tip
Schematic is an injection pressure
operated (IPO) valve (a.k.a. pressure valve)
Pd
where:
Pd = nitrogen pressure
Ab = area of the bellows
IPO
Gas Lift Valve Operation
Valve is in the closed position
What does it takes to get this gaslift valve open?
Look first at the forces trying toclose the valve
Closingforce Pd x Ab
Ab
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Test rack pressure
Zero pressure
Gas Lift Valve Operation
How to get the right Pd?• It is not practical to measure or
set Pd; instead, the valve openingis tested in a test rack
• First, excess nitrogen pressure isapplied to the valve and the valveis ‘aged’ (pressure cycledrepeatedly and equalized)
• The valve is brought to standardtemperature of 60°F (16°C) in awater bath
• The valve is then placed in the testrack where the valve can beexposed to test rack pressures(using nitrogen) to simulate casingpressure
• The nose of the valve is exposed tothe atmosphere
IPO
Valves mounted externally on mandrel
External side guards protect valve
2-3/8 in. (60 mm), 2-7/8 in. (73 mm), 3-1/2 in.(89 mm), 4-1/2 in. (114 mm) and 5-1/2 in.(140 mm)
J-55, N-80, L-80, P110, 13-CR
Mandrels receive 1 in. (25 mm) and 1-1/2 in.(38 mm) valves
From: Lufkin
Gas Lift Valves – Conventional Tubing Retrievable
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CM-1 CM-2
Center Line
AB
CD
Valve DimensionsA: Lug to Collar
B: Lug to Collar (Special Clearance)C: Collar Diameter
D: Collar Diameter (Special Clearance)
CM-1 Valves
1 in. (25 mm)Valve Size
2.375 in. (60 mm) O.D.2 in. (51 mm) Nominal
2.875 in. (73 mm) O.D.2.5 in. (64 mm) Nominal
API EUE
A: 3.783 in. (96 mm) A: 4.335 in. (110 mm)
B: 3.706 in. (94 mm) B: 4.231 in. (107 mm)
C: 3.063 in. (78 mm) C: 3.668 in. (93 mm)
D: 2.910 in. (74 mm) D: 3.460 in. (88 mm)
API NUE
A: 3.689 in. (94 mm) A: 4.251 in. (108 mm)
B: 3.586 in. (91 mm) B: 4.119 in. (105 mm)
C: 2.875 in. (73 mm) C: 3.500 in. (89 mm)
D: 2.670 in. (68 mm) D: 3.235 in. (82 mm)
Gas Lift Valves – Conventional Tubing Retrievable
Valve DimensionsA: Lug to Collar
B: Lug to Collar (Special Clearance)C: Collar Diameter
D: Collar Diameter (Special Clearance)
CM-2 Valves
1.5 in. (38 mm)Valve Size
2.375 in. (60 mm) O.D.2 in. (51 mm) Nominal
2.875 in. (73 mm) O.D.2.5 in. (64 mm) Nominal
3.5 in. (89 mm) O.D.3 in. (76 mm) Nominal
API EUE
A: 4.283 in. (109 mm) A: 4.835 in. (123 mm) A: 5.562 in. (141 mm)
B: 4.206 in. (107 mm) B: 4.731 in. (120 mm) B: 5.427 in. (138 mm)
C: 3.063 in. (78 mm) C: 3.668 in. (93 mm) C: 4.500 in. (114 mm)
D: 2.910 in. (74 mm) D: 3.460 in. (88 mm) D: 4.230 in. (107 mm)
API NUE
A: 4.189 in. (106 mm) A: 4.751 in. (121 mm) A: 5.262 in. (134 mm)
B: 4.086 in. (104 mm) B: 4.619 in. (117 mm) B: 5.152 in. (131 mm)
C: 2.875 in. (73 mm) C: 3.500 in. (89 mm) C: 4.250 in. (108 mm)
D: 2.670 in. (68 mm) D: 3.235 in. (82 mm) D: 4.030 in. (102 mm)
Gas Lift Valves – Conventional Tubing Retrievable
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Gas Lift Valves – Wireline Retrievable
Valves run on wirelineinstalled in side pocketmandrels
Tubing is cut away in allviews
Run into or pulled fromthe well using specifictools to locate and run orpull valves set in theoffset gas lift mandrels
The tool used for wirelinevalve replacement iscalled a “kickover tool”based upon its design
Gas Lift Valves – Wireline Retrievable
Valves run on wirelineinstalled in side pocketmandrels
Tubing is cut away in allviews
Run into or pulled fromthe well using specifictools to locate and run orpull valves set in theoffset gas lift mandrels
The tool used for wirelinevalve replacement iscalled a “kickover tool”based upon its design
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De
pth
SBHP
IPO
Gas Lift Completion – Unloading
How is gas injectedinto a well initially?
• The process ofreplacing completionbrine with injectiongas is calledunloading the well;it is done only onceafter the initialcompletion and afterany well servicingwhere the casing totubing annulus isfilled with liquid
Pressure
Completion fluid brine
Pressure
De
pth
SBHP
Gas Lift Completion – Unloading
Gas pressure andrate is graduallyincreased as gas isinjected into a well’scasing / tubingannulus
The unloading of thewell begins slowly asthe pressure gradientin the casing annulusincreases due toinjection pressure andrate; gas lift valvesopen
IPO
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De
pth
SBHP
Gas Lift Completion – Unloading
Gas injected into thecasing / tubing annulusresults in the pressurepushing the brine througheach of the gas lift valveswhich are wide open
This is a particularlydangerous time for thevalves; if the differentialis too high, the liquidvelocity can be enough tocut the valve seat; then,the valve will not be ableto close and the designwill not work
IPOPressure
De
pth
SBHP
Gas Lift Completion – Unloading
Operators must allowsufficient time for unloading
API RP 11V5 states: take 10minutes for each 50 psi(0.3 MPa) increase in casingpressure up to 400 psi(2.8 MPa), after which, a100 psi (0.7 MPa) increaseevery 10 minutes isacceptable until gas injectsinto the tubing; to reach1000 psi (6.9 MPa) shouldrequire at least 2 hours and20 minutes
A good practice is to assignan operator to the well forthe duration of thisoperation
IPOPressure
Brine may leave the end of tubing or enter the reservoir
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De
pth
SBHP
Gas Lift Completion – Unloading
Once the brine level isbelow the top valve, gaswill enter the tubing andbegin lifting the well
If the tubing pressure isless than the SBHP, thereservoir will begin tocontribute
First production fromthe reservoir is normallyrecovered completionbrine
IPOPressure
De
pth
SBHP
Gas Lift Completion – Unloading
When the secondvalve is uncovered,gas will begin toenter the tubing
IPOPressure
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With more gas leaving casing than entering, the injection pressure must fall
Gas from casing
500 mcfd
Gas tocasing
500 mcfd
Gas fromcasing
500 mcfd
+500
-500
-500
Gas Lift Completion – Unloading
With IPO valves, theinjection gas rate intothe well at the surfacemust be regulated tocontrol the gas entry toapproximately thedesign rate of one valve
Since two valves arepassing injection gas,the pressure in thecasing annulus will fall
IPO
(14.2 mcmd)
(-14.2 mcmd)
(-14.2 mcmd)
(+14.2 mcmd)
(14.2 mcmd)
(14.2 mcmd)
Pressure
De
pth
Gas Lift Completion – Unloading
When the casingpressure falls enough,the top valve will closebased on valvemechanics in a gooddesign
When two valvesrather than one areregulating gas, thepressure must fall,causing the secondvalve to close, leavingonly the lower or theoperating valveregulating gas into thetubing string
IPO
SBHP
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Pressure
De
pth
Gas Lift Completion – Unloading
Since there is still morecasing pressure thantubing pressure at thebottom valve, and, thebottom valve is stillopen, the injection gaswill continue to displacethe brine in the annulusuntil the third valve isuncovered
When all upperunloading valves haveclosed as described,the unloading mode hasended and the well isnow in its gas liftoperating mode
IPO
SBHP
Pressure
De
pth
SBHP
Gas Lift Completion – Unloading
Once again, with moregas leaving the casingthrough two valves, thecasing pressure will falluntil the second valvecloses
Obviously, if there aremore valves deeper, theunloading processcontinues
IPOWhat happens if the third valve injects
too much gas?
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BH
P
Gas Lift Injection Gas Rate
Observe the effect of injecting different injection rates into the well
Case “A” is a small amount of lift gas, case “B” is an increasedamount of gas, and case “C” is a further increase in gas rateinjected
These three cases would generate three production rates
Gas Lift Injection Gas Rate
Pro
du
ctio
n R
ate
Gas Injection Rate
A graph of production rate vs injection rates generates the liftgas performance curve
Once a well has been unloaded, it becomes the responsibility ofthe gas lift technician to periodically visit each well with a testseparator and establish the optimum gas injection rate to producean optimum liquid production rate (the lift gas performance curve)
A
BC
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Gas Lift Injection Gas Rate
In most cases, there is a limited amount of gas available for allthe wells
The optimum rate must be determined within the constraints ofthe gas available for a group of wells
Optimum withinConstrained Group
EconomicOptimum
TechnicalOptimum
Pro
du
ctio
n R
ate
Injection Rate
Practical lift gas rate operating range
Gas Lift Injection Gas Rate
Therefore, for all thepreviously illustratedmaximum and minimumgas injection examplesillustrated, the theoreticallift gas performancecurve has practical upperand lower limits
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Liquids (sales / disposal)
Gas (fuel / sales / gas lift)
Compression
Separator
Injection Gas Distribution
Recall that gas lift is asystem with gascirculating around thesystem
Gas goes into the wells asinjection gas, out of thewells in the gas stream,then is removed from theflow stream (separatedout) in the separatorbefore being compressedand the cycle repeated
The impact of thedistribution of lift gas tothese wells must beconsidered given alimitation in compressedinjection gas rate
Injection Gas Distribution
A mathematically optimumgas lift distribution is foundwhen the lift gas (LG)performance curve slope isequal at each well’soperating injection rate
In other words, if a smallamount of gas could begiven to any well in a groupof wells with an optimumdistribution, it would notmatter which well got theextra gas; all the wellswould benefit similarly
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Injection Gas Distribution
The total lift gas requirement curve
for all wells
Gas Lift – CONTINUOUS Gas Lift
Advantages:• Can handle sand and solids production• Can be used in crooked and deviated wells• Servicing of lift system in well can usually be done with wireline• Can monitor well (pressure, temperature, production logs) with
wireline• Can recomplete some wells through tubing• More produced gas helps gas lift, unlike pumps (rod, ESP)• Flexible over a wide range of rates and depths (unlike ESPs)• Surface equipment at the well has a low profile (unlike rod pumps)• Compatible with surface safety valves (so gas lift can be used to
enhance production from flowing wells)• This system is the most forgiving of artificial lift methods
Continuous gas lift operates most efficiently on moderate to high flow rate wells making significant gas, especially where compression already exists
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Gas Lift – CONTINUOUS Gas Lift
Disadvantages:• Imposes backpressure on the reservoir (unlike pumps or
intermittent lift)• Requires quality gas supply throughout project life• Requires large capital investment (compressor)• Injection gas makes formation gas measurement more difficult
Total Gas = Injection Gas + Formation Gas Total Gas – Lift Gas = Produced Gas from the Reservoir
Hides its operating inefficiency from casual observations very well
Gas Lift – INTERMITTENT Gas Lift
Advantages:• Lower reservoir backpressure (as low as pumps in some cases)• Can be used in crooked and deviated wells• Servicing of lift system in well can usually be done with wireline• Can monitor well (pressure, temperature, production logs) with
wireline• Can recomplete some wells through tubing• More produced gas helps gas lift, unlike pumps (rod, ESP)• Surface equipment at the well has a low profile (unlike rod pumps)• Compatible with surface safety valves
Intermittent gas lift operates most efficiently in wells with high PI with low SBHP or low PI with high SBHP where gas
lift facilities are available and pumping is not practical
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Gas Lift – INTERMITTENT Gas Lift
Disadvantages:• Slugs of liquid can upset production facilities
Slugs of produced liquids (especially offshore) can be intolerable forefficient operation
• Limited to low volume wells, usually < 200 bpd (31.8 m3/d), whichdon’t flow
• Sand can plug standing valve and stick plunger• Requires frequent operator adjustments• Requires quality gas supply throughout project life• Requires large capital investment (compressor)• Injection gas makes formation gas measurement more difficult
Learning Objectives
Understand the concept of gas lift in both unloading mode andoperating mode to start up a gas lift completion and operate thecompletion over its life
Identify the principles of gas lift valve performance and the properlocation of the operating valve and unloading valves
Recognize the characteristics of lift gas performance analysis toproperly establish the most efficient gas lift completionperformance conditions
This section has covered the following learning objectives:
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Electrical Submersible Pumps (ESP)
Gas Lift and ESP Pump Core
Learning Objectives
By the end of this lesson, you will be able to:
Identify the three critical electrical submersible pump designchallenges: solids (sand), gas, and dependable power tomaximize ESP run life (as the average industry ESP run life isapproximately 2.4 years)
Understand the principles of downthrust, upthrust, pumpefficiency, total dynamic head (TDH), number of stagesrequired, and pump horsepower required to successfullyoperate ESPs
Recognize the characteristics of ESP electrical cable, variablespeed drive, and controller components in a functioning ESP
This section will cover the following learning objectives:
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ESPElectric submersible
pump consists of downhole equipment
ESP Pumps
Motor
EqualizerIntake
Pump Cable
ESP Pumps
The most importantcomponents of theelectrical submersiblepump system are aboveground HVAC
Supply
Wellhead
Transformer
440 - 660v 440 - 660v
1000 - 5000v
1000 -5000v
Junction Box
VSD / Control Panel
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Electrical Submersible Pumps
ESP design challenge is proper sizing of the pump• Function of reservoir inflow into the bottom of the well• Rate at which well is produced is related to flow rate brought into
the well as a function of drawdown
The ESP system will be described• Pump• Pump intake• Motor• Equalizer• Cable• Variable speed drive (VSD)• Various operational components
Electrical Submersible Pumps
The heart of an ESPpump are its impellers
These spin at high speedssucking liquid up into thecenter, imparting rotationalenergy to the liquid, andthrowing the liquid out athigh speed
Liquid that gets thrown outof the impeller makesroom for more liquid thatgets pulled in through thecenter of the impeller
Impeller
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Electrical Submersible Pumps
To properly use theenergy that the liquid nowhas in rotational motion,the pump has diffusersthat slow down the liquidand turn it
This changes the velocityof the liquid imparted bythe impeller into head /pressure
Diffuser
V
y u
Electrical Submersible Pumps
Head generated by the pump canbe determined by examining thechange in velocity generated by thepump, V
The two components that make thisup are the velocity in the direction ofthe tip of the impeller, u, and alongthe impeller, y
Only the component u contributesto head
As the flow rate through the pumpincreases, so does component y,which tends to decrease componentu, and thus the head generated Impeller
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TD
H
Rate
Pump Curve
Electrical Submersible Pumps
For a given impeller at agiven rotational speed, themore rate, the less head
Note the plot of the pumpcurve on the TDH vs. Rategraph
The pump curve is thehead that the pump cansupply at a given rate (androtational speed)
V
y u
Electrical Submersible Pumps
The pump curve is not affected by the specific gravity of fluidit is pumping
At a given rotational speed, the same head is generated
The higher the specific gravity of the fluid being lifted, thegreater the number of impellers required
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Radial
Axial
Mixed
Electrical Submersible Pumps
The shape of theimpeller influencesthe fundamentalshape of the headrate curve
Most pumps useradial impellers, butthey may tend towardthe axial shape topick up flow rate atthe expense of head
Electrical Submersible Pumps
To generate sufficienthead, traditional centrifugalpump manufacturerscreate a single, very largeimpeller
This is the kind of pumpused in surface facilities(e.g., waterflood pump)
The efficiency (and thecost) of this pump is high
However, this is not asuitable size and shapepump to install in a well
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Electrical Submersible Pumps
In order to create sufficienthead to lift liquid to thesurface in a normal well,stages are stacked
Each stage feeds into theone above
Each stage acts as a smallincrement of head
Most ESPs have hundredsof stages, all driven by asingle shaft
The size and cost of eachstage is fairly small
Electrical Submersible Pumps
When the length of thestacked stages getsunwieldy, the stages aregrouped into multiplehousings.
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Electrical Submersible Pumps
In most ESPs:• The impellers are keyed to the shaft in the rotational direction• The impellers are free to move up and down the shaft• These impellers are floaters• The impellers usually hover inside the housing, ideally with slight
downthrust on the wear surfaces below the impeller– Forces acting on the impeller are balanced
Electrical Submersible Pumps
If the flow rate is too high through the pump, the impellers will bepushed to the top of the housing and will suffer wear
This condition is called upthrust
Wear in upthrust mode will cause inefficient operation and mayinduce vibration that leads to pump failure
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Electrical Submersible Pumps
If the head is too high for the pump, the impellers will be pushedto the bottom of the housing and will suffer wear
This condition is called downthrust
Pumps are designed for some downthrust
However, if excessive, the wear will cause inefficient operationand may induce vibration that leads to pump failure
Electrical Submersible Pumps
These regions areillustrated on apump curve
• Downthrust• Upthrust• Safe Area
Downthrust UpthrustSafe Area
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Electrical Submersible Pumps
Vendors show anoperating range on theirpump curves that do notdefine the safe range,but a range inside of thehighest efficiency
The relationship of themost efficient range tothe danger areas ofupthrust and downthrustis not known in mostpumps, so the efficiencylimits are used instead
Downthrust UpthrustEfficient
ESP
Sub pump showsthe recommendedoperating range bymarking it with smallsquares at the upperand lower limits oneach curve
Rate, Bbl/d (m3/d)
0 200(31.8)
400(63.6)
600(95.4)
800(127.2)
35 (10.7)
Hea
d, ft
(m
)
30 (9.1)
25 (7.6)
20 (6.1)
15 (4.6)
10 (3.0)
5 (1.5)
0
Standard Catalog Pump CurveCLift 400 FC450 / 3500 RPM / 1 Stg / SG = 1
Head
Power
Eff.
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ESP Manufacturer Pump Curve
Head capacity
24 ft (7.6 m)
800 bbld (124 m3)
ESP Manufacturer Pump Curve
800 bbld (124 m3)
0.22 HP
Brake Horsepower
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ESP Manufacturer Pump Curve
60% Efficiency
PumpEfficiency
ESPs and Produced Gas
What about Gas and High Producing GOR Wells?• ESP pumps do not handle gas efficiently without proper design• How much gas is too much gas? (This area is one of the most
researched items in the recent development of ESPs)• Too much gas can cause “gas lock” as gas occupies space in the
pump, space needed for pumping liquids• Gas volume increases rapidly, especially below a FBHP of about
~500 psi (3.4 MPa)
Oil & water
Oil & water & gas
Bubble point
0
500
1000
1500
2000
2500
Rate
FB
HP
, psi
(M
Pa
)
(3.4)
(6.9)
(10.3)
(13.8)
(17.2)
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Pressure
Dep
th
Annulus pressure
Tubing pressure
ESPs and Produced Gas
How to HandleHigh GOR Wells• In a normal well installation
without a packer, gas issent to the annulus by thegas separator
• The very low gradient forgas means that, for a givenFBHP, the gas can still haveenough pressure at thesurface to flow into the flowline with the pumped fluids
To equalizer
Shaft to pump
Gas and liquid to pump
Gas and
liquid
ESPs and Produced Gas
How to HandleHigh GOR Wells• Well fluids enter the pump
through the pump intake• A standard intake has a
coarse screen to restrictdebris
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To equalizer
Shaft to pump
Liquid to pump
Gas to annulus
Separator impeller
Standard intake
Gas and liquid
ESPs and Produced Gas
How to HandleHigh GOR Wells• Well fluids enter the intake
and gas is routed to theannulus
• This is accomplished bythe pump intake includinga centrifugal gasseparator
How To Handle High GOR Wells• The objective is to keep the gas volume fraction to the pump
at less than 10%
• This objective is conservative, and, at higher pump intakepressures, the pump can handle 35%+ gas, although thegas still takes up volume required for liquid
• Free gas is calculated by subpump / can be calculated by:
ESPs and Produced Gas
Up to 5% gas volume is handled
by a standard equipment ESP centrifugal gas
separator
Add a rotary gas separator when
the gas vol > ~5% to 10%
Source:PEGS 10641.03, pg35
Where:GOR = gas oil ratio (scf/bbl)
Rs = solution gas oil ratio (scf/bbl)Bg = gas volume factor
= 14.7 Z T (1000) / [P x (520 x 5.6148)]
or = 5.05 z T/P
wc = water cut fractionT = Temp (Rankine)P = pressure (psi)
1 /10001 /1000 1
GOR Rs wc BgFG
GOR Rs wc Bg wc Bo wc
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ESP Motors
An ESP motor is not designed like an ordinary motor
A typical electric motor isshown above
This is a very efficientshape electrically and formanufacturing the motor
A common ESP motor is thethree phase, squirrel cagetype, so called because ofthe rotor appearance
Efficiency is greatly reduced
ESP Motors
An ESP motor is notdesigned like an ordinarymotor• An ESP motor works on
the same principles, butmust fit into a long skinnywell bore
• This compromise meansless efficiency and, thus,greater heat buildup
• Also, normal motors havefans for cooling but theESP motor has only theflow of well fluids past themotor to cool it
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ESP Equalizer
This device sits betweenthe pump intake sectionand the motor• The equalizer (a.k.a., the
protector) has three primary functions:1. Keep well fluids out of the
motor
2. Carry the upthrust and/ordownthrust developed in the pump
3. Couple the torquedeveloped in the motor to the pump
Equalizer
Why not just seal the motor?• An ESP motor undergoes
tremendous changes in temperature during normal operation
• The motor is full of a specialblend non-conductive fluid which lubricates and electrically insulates the components; the motor must be full of this fluid to operate properly
• When the motor gets hot, thisfluid needs to expand and the equalizer permits this expansion
ESP Equalizer
Types of Equalizers
There are two primarytypes of equalizers• The bag type or positive
seal protector uses aflexible bag to take thevariation in motor fluidvolume
Well fluids
Flexible bag
Motor fluid
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ESP Equalizer
Types of Equalizers
The other kind ofequalizer is a labyrinthseal• It works by a u-tube
principle and requires asignificant difference inspecific gravities betweenthe motor and well fluid
• Also, it is not useful indeviated wells
• Submersible pumps aretypically placed in the 30°to 40° to 50° deviationangle of the well
ESP Electrical Cable
Cable is the largest and possibly the mostexpensive component of the ESP system
• ESP cable must carry the electrical power tothe pump; it may also carry pressure andtemperature signals back to the surface
– Three copper conductors, one for each phase(can be solid or stranded)
– A layer of electrical insulation– A layer of barrier tape to protect the electrical
insulation from well fluids
– A layer of braid to physically protect andcontain all of the above around each conductor
– A nitrile jacket enclosing the three insulatedconductors
– Metal armor to provide the main physicalprotection and give some extra tensile strength
– Sometimes an expensive lead sheath is usedto keep out H2S gas
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ESP Electrical Cable
Cable is the largest and possibly the mostexpensive component of the ESP system
• All this complexity comes at a cost - up to $50/ft($164/m)
• Cables are rated in terms of conductor size,voltage, and temperature rating
• The biggest challenge is (as is the rest of the ESPsystem) in keeping the OD as small as possible
• If ESP high voltage cable were going to be buriedor run in a conduit on the surface, it would beseveral inches in diameter
• However, in a well, it is restricted to about 1 in.OD (25 mm)
• This is still not small enough near the pump andmotor (usually the largest ODs in the well) and flatcable must be used
• Flat cable has the conductors in parallel whichprovide less mechanical protection and moreelectrical loss
ESP Electrical Cable
Cable is the largest and possibly the mostexpensive component of the ESP system
• Gas typically migrates into the cable• One problem with most ESP cable is that gas
(always present in the annulus) will eventuallymigrate slowly into the insulation of the cable
– Unless corrosive gases are present, this doesnot harm the cable
• However, if the pressure on the annulus isdropped quickly, the cable will suffer fromdecompression (just like a diver getting thebends); gas bubbles will expand and burstthrough the electrical insulation and the cablewill short out
Always de-pressure the annulus of a well with an ESP installed
very slowly, if at all
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ESP Variable Speed Drive VSD
A variable speed drive (VSD) provides flexibility to the otherwisefairly inflexible ESP system… at a price
• The variable speed drive (a.k.a., variable speed controller, variablefrequency controller, etc.) can change the rotational speed of themotor by changing the frequency of the AC power before sending it down hole to the ESP
• By changing the rotational speed of the pump, the operating rangeis greatly expanded
60 Hz
80 Hz
ESP VSD
The VSD provides flexibility to the otherwise fairly inflexible ESPsystem… at a price
• Reasons which justify installation of a VSD:– Produce the well down to the limit of drawdown
(sand, gas, water influx)
– Soft-start that reduces start up current is included– Test and produce at different rates
– Handle changing inflow performance (water flood response,pressure depletion, deteriorating PI, etc.)
– Keep power below power constraints
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ESP VSD
The VSD provides flexibility to the otherwise fairly inflexible ESPsystem… at a price
• A VSD uses high voltage solid-state circuitry to convert the threephase AC into a set of square waves
Choppy DC
Smooth DC
3-phase AC
Squarewaves
Rectifier Filter Inverter
Inverter
Inverter
ESP VSD
The VSD provides flexibility to the otherwise fairly inflexible ESPsystem… at a price
• These square waves are combined to create a pseudo-sine wavefor each phase
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ESP VSD
The VSD provides flexibility to the otherwise fairly inflexible ESPsystem… at a price
• A VSD can only approximate the perfect sine wave that the motor isexpecting
• The more steps the VSD is capable of producing, the closer theapproximation and the more expensive the VSD
• Each point on the cycle where the voltage is higher or lower thanthe sine wave is energy that the motor cannot use
• This lowers the overall efficiency and generates excess heat
VSD
Sine wave
The VSD provides flexibility to the otherwise fairly inflexible ESPsystem… at a price
• Frequencies possible with a VSD are from 20 - 100 hz• The motor horsepower output is a linear function of frequency;
therefore, the higher the frequency to the motor, the greater thehorsepower generated
ESP VSD
2 1 2 1/HP HP Hz Hz• This is why smaller motors can be used in an ESP installation if a
higher frequency is used
0
100
150
200
50
0 20 40 60 80 100Hz
HP
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ESP VSD
The VSD provides flexibility to the otherwise fairly inflexible ESPsystem… at a price
• The pump horsepower required from the motor prime mover is afunction of motor rotational speed (frequency) cubed
32 1 2 1/HP HP Hz Hz• The higher the frequency, the more horsepower required
ESP VSD
The VSD provides flexibility to the otherwise fairly inflexible ESPsystem… at a price
• This means that, up to a certain design frequency, the motor / pumpsystem is underloaded, and, over that frequency, the ESP motor /pump system is overloaded
• This gives an upper limit to the frequency possible for a given anESP system before overloading damages the motor / pump system
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SMI-130 A7 System Performance Using
SubPump
ESP Operation
200(31.8)
400(63.6)
600(95.4)
800(127.2)
7000 (2134)
TD
H, f
t (m
)
6000 (1829)
5000 (1524)
4000 (1219)
3000 (914)
2000 (610)
1000 (305)
01000
(159.0)1200
(190.8)
8000 (2438)
Pump Performance (TDH)CLift 400 FC450 / 173 Stgs / 60.0 Hz
0
Rate, Bbl/d (m3/d)
This well has anexpected rate ofabout 400 bbl/d(64 m3) at thesurface and adownhole volumeof about 500 bbl/d(79 m3) and fallsin the middle ofthe 60 Hz curve
ESP
Advantages:• High production rate capability
• Lowest initial cost for unit rate
• Low bottom hole pressure– Almost as low as beam pump
– Should avoid “pump-off”
• Surface equipment isrelatively small
• Can be used in deviated wells
Disadvantages:• High repair costs and low
salvage value
• Pump life is critical toeconomics and canvary from ~6 months to~6 years; a 2 to 3 year run lifetypical when operated properly
• Pump efficiency low whenhandling high GOR
• Especially sensitive to solids asthe rotor turns at 2500 rpm
• ESPs have a very narrowoperating range
• System is the most unforgivingof artificial lift methods
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Learning Objectives
Identify the three critical electrical submersible pump designchallenges: solids (sand), gas, and dependable power tomaximize ESP run life (as the average industry ESP run life isapproximately 2.4 years)
Understand the principles of downthrust, upthrust, pumpefficiency, total dynamic head (TDH), number of stages required,and pump horsepower required to successfully operate ESPs
Recognize the characteristics of ESP electrical cable, variablespeed drive, and controller components in a functioning ESP
This section has covered the following learning objectives:
PetroAcademyTM Production Operations
Production Principles Core Well Performance and Nodal Analysis Fundamentals Onshore Conventional Well Completion Core Onshore Unconventional Well Completion Core Primary and Remedial Cementing Core Perforating Core Rod, PCP, Jet Pump and Plunger Lift Core Reciprocating Rod Pump Fundamentals Gas Lift and ESP Pump Core Gas Lift Fundamentals ESP Fundamentals Formation Damage and Matrix Stimulation Core Formation Damage and Matrix Acidizing Fundamentals Flow Assurance and Production Chemistry Core Sand Control Core Sand Control Fundamentals Hydraulic Fracturing Core Production Problem Diagnosis Core Production Logging Core Production Logging Fundamentals
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