101.1 Introduction To Al

®

Introduction to Artificial Lift Systems

Objectives Present AL Statistics Provide summary of how each lift method works and key components Advantages and disadvantages of each method How determine lift efficiency Process for lift method selection / elimination Selection exercise

®

2

Major Forms of Artificial Lift (AL)

6Section Courtesy: Weatherford ®

3

AL Distribution: North America, Worldwide

®

4

AL Statistics Approximately 2 Million Oil Wells In The World – About 1 Million Wells Utilize Artificial Lift – Roughly 750,000 of these wells use sucker rod pumps – Gas lifted wells produce more oil than nay other method – More $ are spent on ESPs worlwide than any other method – PCPs are fastest developing / evolving lift method

U.S. U S b beam lift systems t lift about b t 350,000 350 000 wells. About 80 percent of U.S. oil wells are stripper wells, making less than 10 bpd ®

5

®

Reciprocating Rod Pump or Beam Pump Overview

Well Needing Some Type of Artificial Lift This well is dead

Tank

Tubing Casing Fluid Level Oil Formation

®

7

Well Being Produced with Artificial Lift

Sucker Rods Pumping p g Unit

Tank

T bi Tubing Casing Fluid Level P Pump ®

Oil Formation

8

Conventional Beam Pumping Unit

®

9

Beam Pump Components S f E i t Surface Equipment – Units Conventional , Mark, Air Balance, Hydraulic etc. – Wellhead – Polished Rods – Prime movers – Gearbox (part of unit) – Sheaves – Belts – Transformers

Downhole Equipment – – – –

Pumps R d and Rods d couplings li Tubing Gas separator when needed

Production Optimization – Surface and calculated downhole dynamometer cards – Valve checks – Pump Off Controller / Timers – Power Measurement – Downhole/Surface sensors ®

10

More Common Units

Mark II

Air Balance Unit ®

C Conventional ti l Unit U it 11

Tower Long Stroke Units

®

12

Hydraulically Powered Surface Units

®

13

Beam Advantages High System Efficiency Optimization Controls Available Economical to Repair and Service Positive Displacement/Strong Drawdown Upgraded pg Materials Reduce Corrosion Concerns Flexibility - Adjust Production Through g Stroke Length and Speed High Salvage Value for Surface & Downhole Equipment ®

Disadvantages Potential for Tubing and Rod Wear Gas Oil Ratios Gas-Oil Most Systems Limited to Ability of Rods to Handle Loads - Volume Decreases As Depth Increases Environmental and Aesthetic Concerns

14

Beam System Application Considerations Depth

Volume

Max

Typical

100-11,000'

16,000'

30-3355 m

4878 m

5-1500 bpd p

5000 bpd p

1-238 m3/D

800 m3/D

Temperature100-350F

I li ti Inclination

550F 38-177 C

288 C

0 20 d 0-20 deg

0 90 D 0-90 Deg L Landed d d Pmp P

landed pmp

(<15deg/100) Build

4500

Gas Handling: Fair to Good especially if below perfs

4000

Solids Handling: Fair to Good

3500

Fluid Gravity: >8 API

3000

Servicing: Workover or rod pulling rig

2500

Prime mover: Gas or electric

BFPD

Corrosion Handling : Good to Excellent

2000

Offshore: Not typical

1500

Efficiency; 40-60 %

1000 500 0 1

®

2

3

4

5

6

7

8

9

10

Fluid Lift, ft X1000

11

12

13

14

15

15

®

Progressing Cavity Pumps (PCP)

PCP Components

®

17

PCP Advantages Low Capital Cost Low Surface Profile for Visual and Height Sensitive Areas High System Efficiency Simple p Installation,, Quiet Operation Pumps Oils and Waters with Solids Low Power Consumption Portable Surface Equipment Low Maintenance Costs Use In Horizontal/Directional Wells

®

Disadvantages Limited Depth Capability Temperature S Sensitivity iti it tto P Produced d d Fluids Low Volumetric Efficiencies in High-Gas Environments P t ti l for Potential f Tubing T bi and d Rod Coupling Wear Requires Constant Fluid Level above Pump

18

PCP Application Envelope Depth

Volume

Temperature

Inclination

Max

Typical

1000-5000'TVD

9,800' TVD

330-1,550

4878 m

5-2500 bpd

5000 bpd

1-387 m3/D

795 m3/D

75-170 F

300+F

24 77 C 24-77

149 C

N/A

(<15deg/100') Build (<15deg/30m) Build

®

Corrosion

Excellent (regarding Pump)

Gas Handling

Good (especially if pump below perfs)

Fluid Gravity

Below 45 API (dependent on aromatics content)

Solids

Excellent

Service/Repair

Workover or pulling rig usually required

Prime Mover Type

Electric motor or IC Engine

System Efficiency

50-75% if no wear or gas interference 19

®

Gas Lift

Gaslift Rotative System

®

Single Well

21

Gaslift Advantages High Degree of Flexibility and Design Rates Wireline Retrievable Handles Sandy Conditions Well Allows For Full Bore Tubing Drift Surface Wellhead Equipment Requires Minimal Space Multi-Well Production From Single Compressor Multiple or Slimhole Completion ®

Disadvantages Needs High-Pressure Gas Well or Compressor One Well Leases May Be Uneconomical Fluid Viscosity Bottomhole Pressure Hi h Back-Pressure High B kP (may not be able to lower p pressure on formation as well as other methods of lift)

22

Gaslift Application Considerations Depth

Volume

Temperature

Inclination

Max

Typical

5000-10000' TVD

15,000' TVD

1524-3048 m

4573 m

100-10,000 bpd

30,000 bpd

16-1600 m3/D

4770 m3/D

100-250 F

400 F

37 128 C 37-128

204 C

0-50 deg

70 deg Sort / medium radius

C Corrosion i

E Excellent ll t with ith upgraded d d materials t i l

Solids

Excellent. Sand does not go through valves

g Gas Handling

Excellent

Fluid Gravity

Best > 15 API

Service/Repair

Wireline or Workover rig (new methods trying to overcome this)

Prime Mover Type

Compressor w Electric motor or IC Engine

System Efficiency

10-30%

®

23

®

Plunger: Low Rate and Gas Wells

Plunger Lift

®

25

Plunger Lift Advantages Requires No Outside Energy Source - Uses Well’s Energy to Lift Dewatering Gas Wells Rig Not Required for Installation Easy Maintenance Keeps Well Cleaned of Paraffin Deposits Low Cost Artificial Lift Method Handles Gassy Wells Good in Deviated Wells Can Produce Well to Depletion ®

Disadvantages Specific GLR’s to Drive System Low Volume Potential (200 BPD) Solids Requires Surveillance to Optimize Note: Many yp plunger g installations lift only few bbls per day… less than 5 bpd in many cases.

26

Plunger Lift Application Considerations Max

Typical

to 8000' TVD

19,000' TVD

2440 m

5790 m

1-5 bpd p

200 bpd p +/-

.2-.8 m3/D

32 m3/D

to 130 F

500 F

54C

260 C

Inclination

0-30 deg

60 deg

Corrosion

Excellent

Gas Handling

Excellent

Solids

Poor Brush or special plungers help

Fluid Gravity

Low viscosity best

Service/Repair

Wellhead catcher or wireline

Prime Mover Type

N/A uses well's well s energy

System Efficiency

N/A unless compressed gas added

Depth

Volume

Temperature

®

27

®

Hydraulic Pumping Systems

Unidraulic Hydraulic System, Pumps

®

29

Piston System Advantages Often “Free” or Wireline Retrievable Positive Displacement Strong Drawdown Double-Acting HighVolumetric Efficiency Good Depth/Volume Capability +15,000 ft. Deviated Wells Multi-Well Production From Single Surface Package Horsepower p Efficiency y

®

Disadvantages Solids Requires Specific Bottom Hole Assemblies Medium Volume Potential (50 - 1000 BPD) Require Service Facilities Free Gas Requires HighPressure S f Surface Li Line 30

Hydraulic Piston Application Considerations Max

Typical

7,500' to 10,000' TVD

17,000" TVD

2286-3048 2286 3048 m

5183 m

50-500 bpd

4000 bpd

8-80 m3/D

800 m3/D

100-250 100 250 F

500 F

37-121 C

260 C

Inclination

0-20 deg

0-90 deg pump placement

Corrosion

Good

Gas Handling

Fair similar to Beam Pump

Solids

Very yp poor will fail pump p p

Fluid Gravity

>8 API in general

Service/Repair

Pump up or wireline

Prime Mover Type

Gas or electric motor driving Triplex Pump at Surface

System Efficiency

Excellent 40-50% or greater

Depth

Volume

Temperature

®

31

Jet Lift Advantages

Disadvantages

No Moving Parts High Volume Capability “Free” Free Pump Deviated Wells Multi-Well Production from Single Surface Package Low Pump Maintenance

®

P d i Rate R t Producing Relative to Bottomhole Pressure Some Require Specific Bottomhole Assemblies Lower Horsepower Efficiency High-Pressure Surface Line Requirements 32

Hydraulic Jet Lift Application Considerations Max

Typical

5000-10,000' TVD

15.000 TVD

1524-3048 m

4574 m

300 1000 bpd 300-1000

15 000 bpd 15,000

5-160 m3/D

2385 m3/D

100-250 F

500 F

37-121 C

260 C

Inclination

0-20 deg

0-90 deg pmp placement

Corrosion

Excellent

Gas Handling

Good can set below perfs

Solids

Will handle some solids

Fluid Gravity

>8 8 API in general

Service/Repair

Pump up or wireline

Offhore

Possible but desk space concerns

yp Prime Mover Type

Gas or electric motor driving g Triplex p Pump p at Surface

System Efficiency

Poor 10-30 % like gaslift

Depth

Volume

Temperature

®

33

®

Electric Submersible Pumps (ESP)

Typical ESP System

®

35

ESP Advantages Hi h Volume V l d High and Depth Capability High Efficiency Over 1,000 BPD Low Maintenance Minor Surface Equipment Needs Good in Deviated Wells Adaptable p to All Wells With 4-1/2” Casing and Larger Use for Well Testing ®

Disadvantages Available Electric Power Limited Adaptability to Major Changes in Reservoir Difficult to Repair In the Field Free Gas and/or Abrasives High Viscosity Higher Pulling Costs

36

ESP Application Considerations Depth Volume

Max 1000-10,000' TVD 305-3050 m 100-20,000 bpd 16-3188 m3/D

Typical 15.000 TVD 4373 m 30,000 bpd +/4770 m3/D

Seals (C/L) o SeaLAST can withstand BHTs of up to 300 °F (149C) o CL180 O-rings can withstand BHTs of up to 450 °F (232 C) Motors (C/L) o 375 SP motors can go up to 250 °F operating temp (121C) o 450 SP1 motors can go up to 325 °F operating temp (163 C) o 562 KMH-A and SP1/XP motors can go up to 325 °F operating temp (163 C) o 725 XP/VC motors can go up to 325 °F F operating temp (163 C) Special trim motors for SAG-D may rate for higher temperatures Inclination 10-90 deg <10 Deg/100' build Corrosion Handling Good G Handling Gas H dli P Poor to t Fair F i separator t or completions l ti Solids Poor to fair new specials stages better than past Fluid Gravity >10 API Service/Repair Must pull tubing Offshore Not that good since must pull tubing to service (new techniques?) Prime Mover Type Electric motor downhole System Efficiency 35-60% depending on diameter of system ®

37

Summary: AL Characteristics

®

38

®

Lift Method Power Efficiency (What fraction of input power actually y lifts fluid to the surface at the desired rate?)

Lift Method Efficiency: ESP The efficiency of the system is the result of multiplying the efficiencies of individual components

η system = ηtxfr ×η vsd ×η cable ×η motor ×η prot ×η pump

®

40

Lift Method Efficiency: Beam Motor ηmotor t

Unit ηunit

Stuffing box ηstuff

Rods η rods

η system = η motor ×ηunit ×η rods ×η stuff ×ηTHP ×η pump Bomba ηpump ®

41

Lift Method Efficiency What do you think may be the cause of losses in other lift methods – PCP – Jet pump – Gaslift

Guess the order of efficiency for AL methods…… methods

®

42

Lift Method Efficiency Ultimately the efficiency of the system is:

ηsystem =

Hydraulic HP HP In

Out

=

ηsystem =

Energy Out Energy In

Hydraulic HP Out Q× Lift× s . g ∝ kWIn / 0.746 0 746 HPIn

1 HP = 550 ft.lb/sec – How do we takes care of units to convert BPD x Lift x s.g to HP?

BPD× Lift× s . g HP to lift fluids = 135730

®

43

Lift Method Efficiency The efficiency for a system can be determined using the following formulas (depending on data available) available).

ηsystem

ηsystem =

ηsystem

Q(bpd) × Lift(ft) × s . g . 135730 × HP In

Q(bpd) × Lift(ft) × s . g . = kW 135730 × 135730× 0.746

Q(bpd) Q( p ) × Lift ((ft)) × s . g. = 181944 × kW in

Note: For Gaslift, the denominator becomes requires the power to operate the compressor

®

44

Efficiency Comparison (versus other ALS) Energy Efficiency:

Most Typical Range

Overall Range

Reasons for Inefficiencies:

PCP

Slippage through the pump; friction effect in pump; losses in energy transmission from surface to pump; internal losses of the surface drive system; handling of multiphase fluids

Rod

Slippage through the pump; losses in energy transmission from surface to pump; extra-energy utilized to overcome peaks in upstrokes; handling of multiphase fluids

ESP

Dynamic pump with maximum mechanic efficiencies not greater than 80% (60% if radial di l configuration); fi i ) El Electrical i l llosses iin b bottomhole h l motor and power cable; equipment itself consume about 30% of the energy; handling of multiphase fluids Considerable amount of energy utilized to handle power fluid; slippage through the pump; energy losses associated to surface equipment; equ p e t; handling a dl g o of multiphase ult p ase fluids lu ds

Recipr. Hyd

Jet Hyd.

Considerable amount of energy utilized to handle power fluid; internal energy losses in the diffuser of the pump; energy losses associated to surface equipment; handling of multiphase fluids

GL Cont.

Most of the energy utilized to compress the gas (over 40%); friction losses across pipelines and wellbore annular area; further expansion of gas

GL Int.

Most of the energy utilized to compress the gas (over 40%); friction losses across pipelines and wellbore annular area; further expansion off gas, th the non-continuous ti operation ti off th the system t

0

10

20 ®

30

40

50

60

70

80

90

100 %

From Weatherford 45

Power Efficiency: Summary Power efficiency is desirable. However obtaining the desired rate and increased run life usually have higher priority. priority Low power efficiency may relate to shorter run lives if related to harsh conditions or wear. However low power efficiency could relate to an oversized i d design d i and d may / may nott relate l t to shorter run lives. Many times for AL using pumps pumps, low efficiency is related to gas interference. You must have p power meter on individual well to obtain power efficiency. ®

46

®

Lift Method Selection

AL Lift/Rate Capabilities ( Approximate ) 2.

High Volume

35,00 35 00 0

Hydraulic Jet Pumps, Electric Submersible Pumping and Gas Lift

30,000

Gas Lift

ESP 25,00 0 20,000

15,000

Hydraulic Jet Pump 10,000

16,0 000

15,0 000

14,0 000

13,0 000

12,0 000

11,0 000

10,0 000

9,0 000

8,0 000

7,0 000

6,0 000

5,0 000

4,0 000

3,0 000

2,0 000

5,000

1,0 000

Barrels per D B Day

These types Th t off charts are approximate pp and cannot cover all possible conditions

Elimination Process

Lift Depth ®

48

AL Lift/Rate Capabilities ( Approximate ) 2.

Elimination Process

4 500 4,500

Lower Volume

3,500 3,000 2,500 2 000 2,000

Recip. Hydraulic 1,500

Recip. Rod Pump 1,000

PC Pumps 500

16,000

15,000

14,000

13,000

2,000 12

11,000

10,000

9,000 9

8,000 8

7,000

6,000 6

5,000 5

4,000 4

3,000

1,000

Plunger Lift 2,000

Barrels per Day B

Reciprocating Hydraulic Pumps, PC P Pumps, Rod Pumps & Plunger g Lift

4,000

Lift Depth ®

49

AL Depth/Rate Capabilities ( Approximate) SI Lower Rate Applications 700.0 R i H Recip. Hydraulic d li

650.0 600.0 550.0

PCPumps

500.0 500 0 450.0

3

m /D

400.0 Recip Rod Pumps

350.0 300.0 250.0 200.0

Plunger Lift

150.0 100.0 50.0 0.0 0

500 1000 1500 2000 2500 3000 3500 4000 4500 5000 5500 Depth, m

®

50

Depth/Rate Capabilities ( Approximate) SI

Hi-Volume Selection of Lift

3

m /D

6000.0 5500.0 5000.0 4500.0 4000.0 3500.0 3000 0 3000.0 2500.0 2000.0 1500.0 1000 0 1000.0 500.0 0.0

Gas Lift ESP

J tP Jet Pump

0

500 1000 1500 2000 2500 3000 3500 4000 4500 5000 Depth, m

®

51

Summary Information has been presented on the major methods of AL. Already enough information has been presented that would allow you to rule out certain methods of lift for partic lar applications particular applications. Later sections describe the various systems in detail, di discuss operational ti l considerations, id ti discuss di design d i and d analysis and other details of each system. Selection problems with system performance and Capex and Opex considerations will be discussed later in this class as more detailed discussions of lift methods are presented presented. ®

52

Select Best AL System for Conditions 1- Depth: 3000 ft (914m) Some sand present: S Some viscosity: i it Production: 800 bpd (127 m3/D) 2- Depth: 7000 ft (2134m) No sand present Production: 500 bpd (80m3/D) Oil and Water

4- Depth: 3000 ft (914m) No sand present: 5- Production: 3000 bpd (477m3/D) Depth: 13000 ft (3963m) No sand present 6- Production: 30,000 bpd (4770 m3/D)

3- Depth: 12000 ft (3658m) Little sand present Production: 50 bpd (8m3/D) ®

53

Select Best AL System for Conditions 1-Profundidad: 3000 ft - ~ 914 m Arena presente Crudo poco viscoso Caudal deseado: 800 bpd (127 m3/dia) 2-Profundidad: 2 Profundidad: 7000 ft - ~ 2133 m No arena existente Caudal deseado: 500 bpd (80 m3/dia) Petróleo & agua ®

3-Profundidad: 12000 ft- ~ 3657 m No arena presente Caudal deseado: 50 bpd (8 m3/dia) 4-Profundidad: 12000 ft - ~ 3658 m No arena presente Caudal deseado: 3000 bpd (477 m3/dia) 5-Profundidad: 13000 ft- ~ 3962 m No arena presente Caudal deseado Cauda deseado: 30,000 bpd (4769 m3/dia) 54