Introduction to Artificial Lift - Active Learnercloud1.activelearner.com/contentcloud/portals/hosted3/PetroAcademy/... · Nodal Analysis principles also illustrate how flow to the

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

Gas Lift and ESP Pump Core ═══════════════════════════════════════════════════════════════════════════════════

©PetroSkills, LLC. All Rights Reserved. _________________________________________________________________________________________________________

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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).


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


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.


Pwf

Pres

Qliquids

… tubing data for outflow


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


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


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…


…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


Motor

Well's Natural

Energy


Motor


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


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




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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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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 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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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


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


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)


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


2.875 in. (73 mm) O.D.2.5 in. (64 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)




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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 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 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


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


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


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


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


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


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


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


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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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


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


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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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




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Electrical Submersible Pumps (ESP)


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




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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


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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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


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


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


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


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


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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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


When the length of thestacked stages getsunwieldy, the stages aregrouped into multiplehousings.



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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


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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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


These regions areillustrated on apump curve

• Downthrust• Upthrust• Safe Area

Downthrust UpthrustSafe Area



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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)


800 bbld (124 m3)

0.22 HP

Brake Horsepower



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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


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


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


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:


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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• 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



• 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


• 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


• These square waves are combined to create a pseudo-sine wavefor each phase



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ESP VSD


• 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


• 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 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


• 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


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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