Art Lift Slide Show

Artificial Lift Systems for Oil Production

March 2012

Table of Contents

Definition of Artificial Lift How an Oil Well is Produced Types of Artificial Lift Systems

Beam Pumping/Sucker Rod Pumps Electric Submersible Pumps Progressing Cavity Pumps Subsurface Hydraulic Pumps Gas Lift

Summary Selection of Artificial Lift Method References

Definition of Artificial Lift

Artificial lift refers to the use of artificial means to increase the flow of liquids from a oil production well.

Generally this is achieved by : the use of a mechanical device inside the

well (pumps) or decreasing the weight of the hydrostatic

column by injecting gas into the liquid some distance down the well.

Why Artificial Lift

Artificial lift is needed in wells when there is insufficient pressure in the reservoir to lift the produced fluids to the surface, but often used in naturally flowing wells (which do not technically need it) to increase the flow rate above what would flow naturally.

Used to lower the producing bottomhole pressure (BHP) on the formation to obtain a higher production rate from the well.

The produced fluid can be oil and/or water, typically with some gas included.

Types of Artificial Lift Systems

Artificial-lift methods fall into two groups, those that use pumps and those that use gas.

Pump Types

Beam Pumping / Sucker Rod Pumps (Rod Lift) Electric Submersible Pumps (ESPs) Progressive Cavity Pumps (PCPs) Subsurface Hydraulic Pumps

Gas Method

Gas Lift

The most economical (for example using the net present value) artificial lift method must be selected based on:

Geographic location

Capital cost

Operating cost

Production flexibility

Reliability

Mean time between failures

Artificial Lift There are approximately 2 Million oil

wells in operation in the world

Over 1 Million wells utilize some type of artificial lift

Close to 900,000 Rod, ESP and PCP pumps

Source: ABB

Sucker-Rod Lift System

Oldest and most widely used method of artificial lift.

This method can lift 150 BFPD from 14000 ft, and more than 3000 BFPD from less than 2000 ft.

Sucker-Rod Lift System

Rod PumpingSucker Rod Pumps (Donkey pumps or beam pumps) are the most common artificial-lift system used in land-based operations

A motor drives areciprocating beam, connected to a polished rod passing into the tubing via a stuffingbox

The rod string continues down to the oil level and is connected to a plungerwith a valve (pump) that is inserted or set in the tubing near the bottom of the well.

Each upstroke of the beam unit lifts the oil abovethe pumps plunger.

Downhole Sucker-Rod PumpsThe most important components are: the barrel, valves (travelingand fixed (or static or standing)) and the piston.

Barrel: The barrel is a long cylinder, 10 to 36 feet long, with a diameter of 1 inches (32 mm) to 3 inches (95 mm).

Piston/Plunger: This is a nickel-metal sprayed steel cylinder that goes inside the barrel

Valves: The valves have two components- the seat and the ball - which create a

complete seal when closed

Piston rod: This is a rod that connects thepiston with the outside of the pump

At the same time, the pressure drops in the space between the standing and travelling valves, causing the standing valve to open. Wellbore pressure drives the liquid from the formation through the standing valve into the barrel below the plunger. Lifting of the liquid column and filling of the barrel with formation liquid continues until the end of the upstroke.

Pumping Cycle OperationAt the start of the upstroke, the travelling valve closes due to the high hydrostatic pressure in the tubing above it. Liquid contained in the tubing above the travelling valve is lifted to the surface during the upward movement of the plunger

The travelling valve immediately opens, and the standing valve closes. When the travelling valve opens, liquid weight is transferred from the plunger to the standing valve. During downstroke, the plunger makes its descent with the open travelling valve inside the barrel filled with formation liquid. At the end of the downstroke, the direction of the rod strings movement is reversed, and another pumping cycle begins.

Pumping Cycle Operation

After the plunger has reached the top of its stroke, the rod string starts to move downwards.

Type of Pumps

Rod Pumps:

Also called insert pumps because they are run (inserted) in the producing tubing.

No need to pull out the tubing string, which reduce maintenance time and downtime.

Tubing Pumps:

The working barrel of this pump is coupled with the production-tubing string.

Rod Pumping

System parts are manufactured to meet existing API standards.

Numerous manufacturers can supply each part, and all interconnecting parts are compatible.

Sucker rods: From to 1 inches in diameter. 25 or 30-ft lengths

DOWNHOLE GAS SEPARATORS

Used in gassy wells to increase the volume of free gas removed from the liquids before reaching the pump.

These separators are called gas anchors.Natural Gas Anchor Poor Boy Gas Anchor

DOWNHOLE PUMP SIZING

PD = pump displacement, BFPDS = stroke length, inchesN = pumping speed, spmd = diameter of the pump plunger, inches

21166.0 dNSPD =LEAKAGE LOSSES

Efficiency Overall Efficiency 45 - 60% Depending on design, higher energy losses can be on the subsurface equipment Motors for pumping units between 1 and 125 HP

Videos about Sucker Rod-Pumping System

ROD LIFT SYSTEM ADVANTAGES

High system efficiency

Gas or electricity can be used as a power source

Economical to repair and service

High-temperature and viscous fluids can be lifted

Upgraded materials can reduce corrosion concerns

Flexibility -- adjust production through stroke length and speed

High salvage value for surface unit and downhole equipment

ROD LIFT SYSTEM DISADVANTAGES

Limited to relatively low production volumes, less than 1,000 barrels per day {up to about 40 liters (10 gal) per stroke}

Incompatible with deviated wells, even with the use of rod protectors. Maximum of 30 deviated wells with smooth profiles and low dogleg severity.

Limited ability to produce fluids with sand.

Paraffin and scale can interfere with the efficient operation of sucker-rod pumping systems.

The polished-rod stuffing box can leak.

Rod Pumps Market

Over 750,000 in operation World Wide

350,000 in operation in USA

400,000 units installed in rest of world

Electrical Submersible Pumps (ESPs)

ESP Facility

ESPs incorporate an electric motorand centrifugal pump unit run on a production string and connected back to the surface control mechanism and transformer via an electric power cable.

ESPsThe downhole components are suspended from the production tubing above the wells' perforations.

Above the motor is the seal section, the Intake or gasseparator, and the pump.

The power cable is banded to the tubing and plugs into the top of the motor.

As the fluid comes into the well it must pass by the motor and into the pump.

This fluid flow past the motor aids in the cooling of the motor. The fluid then enters the intake and is taken into the pump.

Each stage (impeller/diffuser combination) adds pressure or head to the fluid at a given rate.

The Pros

ESP

High Volume and Depth Capability.

High Efficiency Over 500-1000 bpd.

Low Maintenance (w/o sand, etc).

Good in Deviated Wells.

Minor surface equipment requirements

Possible in 4 Casing and Larger.

ESP applicable at any time of the reservoir life.

The Cons

ESP

Requires Electric Power Source. Adapt to Reservoir Changes? (VSD). Field repair usually impossible. Problem production: Solids, gas, other. Viscosity: reduces , flow, etc. Usually must pull tubing if problems.

ESP Market

90,000 units in the world

60,000 units in Russia

A few thousand units in the US

ESP Growth Areas More ESPs on depleting wells

Focus on: Deep Water More ESP in wells that might be

producing with gas lift

Design of an ESP installation

Well physical data: Casing and liner sizes, weights, and

setting depths.

Tubing size, type, weight, and thread.

Total well depth.

Depth of perforations or open hole interval.

Well inclination data.


Well performance data: Tubinghead pressure at the desired rate. Casinghead pressure. Desired liquid production rate. Static bottomhole pressure or static liquid level. Flowing bottomhole pressure or dynamic liquid level. Productivity data (PI or qmax for the Vogel model). Producing gas/oil ratio. Producing water cut or water/oil ratio. Bottomhole temperature at desired liquid rate.


Fluid properties:

Specific or API gravity of produced oil. Specific gravity of water. Specific gravity of produced gas. Bubble point pressure. Viscosity of produced oil. PVT data of produced fluids (volume factors, solution

GOR, etc.).


Surface power supply parameters:

Primary voltage available at the wellsite. Frequency of the power supply. Available power supply capacity.


Unusual operating conditions:

Production of abrasives, especially sand.

Paraffin deposition.

Emulsion formation.

Type and severity of corrosion.

Extremely high well temperatures.

How Much can the well produce?

How Much does it take?

Fluid will flow up the tubing only if the pressure at the tubing intake (bottom of the tubing) is greater than the hydrostatic weight of the fluid, plus the friction pressure losses in the tubing, plus thewellhead discharge backpressure.

Will it Flow?

This intersection point (surface flow rate, bottom hole pressure) is the point at which the well should actually flow under stabilisedconditions.

Will it Flow?

The curves do not intersect. This well would not flow at any rate. A pump must supplement the energy supplied by the reservoir in order to produce fluid at the surface. The precise amount of energy needed is represented by the vertical separation between the two curves.

How Much Do We Have To Add?

By measuring the difference between the tubing intake pressure requirement curve and the wells inflow performance curve, we obtain a curve representing the pressure increase required across the pump as a function of rate..

The curves are based on fresh water and a fluid viscosity of 1 cp. The horizontal axis represents actual rate through the pump. Head, brake horsepower, and efficiency represent more than one pump stage.

The designer must compare the well requirementscurve (similar to previous Figure ) with the performance characteristics of different pumps.

These performance characteristics are typically given in the form of pump curves.

The intersection of the two curves on this plot represents the point at which the well would be expected to produce under stable conditions.

ESP Design Example

Well Data: Casing from surface to 5600 ft: 7 in. OD and 26 lbm/ft Liner from 5530 to 6930 ft: 5 in. OD and 15 lbm/ftTubing: 2 in. and 6.5 lbm/ft J55 EUEPerforations: 6750 to 6850 ftPump setting TVD (just above liner top): 5500 ft.

Well Fluid Conditions: Specific gravity of water, SGw = 1.085 Oil API = 32 (SGo = 0.865) SGg = 0.7 Bubble point pressure of gas, Pbp = 1500 psig Viscosity of oil: not available.

ESP Design Example (cont)

Power Sources. Available primary voltage: 12470 V; frequency: 60 Hz.

Production Data. Tubing head pressure, Pth= 100 psigCasing pressure, Pch = 100 psigPresent production rate, Q = 850 BFPD Well flowing pressure, Pwf = 2600 psig Static bottomhole pressure, Pr = 3200 psig at 6800 ftBottomhole temperature, Twf: 160FMinimum desired production rate: 2300 BFPD (standard cond.)GOR: 300 scf/STBWater cut: 75%.


Since Pwf > Pbp psiBPDPwfPr

QPI /42.126003200

850)( ===

psigPIQdPrPwf 1580)42.1/2300(3200)/( ===The new Pwf at the desired production rate Qd is

The PIP is calculated correcting the Pwf for the difference in the pump setting depth and datum point (1300 ft), friction loss negligible:

)/31.2/(),( psiftSGftHeadPPPwfPIP Lhh ==03.1085.175.0865.025.0 =+=+= SGwXwSGoXoSGL

[ ] psigPIPPIP 100031.2/)03.11300(1580 ==


The total flow Vt of oil, gas and water at the pump intake is:

BFPDinVwVVoVt IG ++=

The solution gas/oil ratio at the pump intake pressure is:

( )2048.1

00091.0

0125.0

)1010(18/

=

Tf

API

bPSGgRs

( ) STBscfRs /180)1010(18/10007.0

2048.1

16000091.0

320125.0

=

=


Therefore

The flow of oil Vo at the pump intake is:

BoXoQdVo =

175.1000147.0972.0 FBo +=

Where Bo is the formation volume factor and is calculated by

362160*25.1865./7.018025.1/ =+=+= TfSGoSGgRsF

STBbarrelactualBo / 12.1)362(000147.0972.0 175.1 =+=

And 64412.125.02300 BOPDVo ==


And

The flow of free gas at the pump intake is:

)( )( BgfactorvolumegasVgasfreeV FGIG =

SGFG VVgnin SolutioGasgasofvolumeTotalV ==

MscfGORBOPDVg 5.1721000/30025.023001000/)( ===

[ ] MscfRsBOPDVSG 5.1031000/180)25.02300(1000/)( ===


And

Therefore:

695.1035.172 MscfVFG ==

[ ] McfbblPTfZBg /62.27.1014/)160460(85.004.5/)04.5( =+==

BGPDMcfbblMcfVIG 181/62.269 ==


The flow of water is

Therefore:

25501725181644 BFPDBWPDBGPDBOPDVt =++=

%7100*)2550/181(100)/( % === VtVgasfreeof IG

BWPDXwQdVw 172575.02300 ===

% of free gas at the pump intake


And:

) ( ftinPIPPdPressureIntakePressureDischargeTDH ==

HwhFtdepthPumpPd ++=

The Total Mass of Produced Fluid (TMPF) is

The Total Dynamic Head (TDH) is

SGcomppsi1ftPIPftPIP /)/3.2()( =

)4.626146.5/( = BFPDTMPFSGcomp

[ ] 4.626146.5)()( += SGwBWPDSGoBOPDTMPF)5.379/29( + SGgBOPDGOR


And:

DlbmTMPF /839064=

Therefore

939.0)4.626146.52550/(839064 ==SGcomp

[ ] 5.379/29575300(4.626146.5)085.11725()865.575( ++=TMPF

ftpsi1ftftPIP 2460939.0/)/3.21000()( ==


For 5500 ft

The tubing friction loss (Ft) is read from Figure below for 2550 BPD

depthofftftFt 1000/49=

ftFt 270=

SGcompPthHwh /31.2=

ftHwh 246939.0/31.2100 ==


Finally

The discharge pressure is

ftPd 60162462705500 =++= 355624606016 ftPIPPdTDH ===

Select the pump type with the highest efficiency per stage:Head =41.8 ft at 2550 B/D

No of stages = 3556/41.8= 85

BHP= 1.16 *85*0.939= 92.5 HP

Progressing Cavity Pumps (PCPs)


Consist of a surface drive, drive string and downhole PC pump

The PC pump is comprised of a single helical-shaped rotor that turns inside a elastomer-lined stator

The stator is attached to the production tubing string and remains stationary during pumping.

The rotor is attached to a sucker rod string which is suspended and rotated by the surface drive.

PCP usually rotates between 300 and600 rev/min,

Rotation of the rod string by means of a surface drive system causes the rotor to spin within the fixed stator, creating the pumping action necessary to produce fluids to surface.


SEVERAL PCP DESIGNS

PUMP DISPLACEMENT (Single-lobe PC pump)Pump eccentricity (e), is the distance between the centerlines of the major and minor diameters of the rotor.

ROTOR MOTION IN A SINGLE-LOBE PC PUMP

Pump eccentricity (e), is the distance between the centerlines of the major and minor diameters of the rotor.

Pump Displacement RatePump eccentricity (e), is the distance between the centerlines of the major and minor diameters of the rotor.

PC pump displacements generally range from 0.02 m3/d/rpm [0.13 B/D/rpm] to > 2.0 m3/d/rpm [12.6 B/D/rpm].

The theoretical flow rate of a PC pump is directly proportional to its displacement and rotational speed and can be determined by:

where qth = theoretical flow rate (m3/d [B/D]), s = pump displacement (m3/d/rpm [B/D/rpm]),

and = rotational speed (rpm).

The actual flow needs to consider some slippage rate.

Pump eccentricity (e), is the distance between the centerlines of the major and minor diameters of the rotor.

Effect of fluid slippage on volumetric pump efficiency.

Animation about PCPs

PCPs ADVANTAGES

Low capital investment

High system efficiency (typically in the 55 to 75% range)

Low power consumption

Pumps oils and waters with solids

Preferred method for lifting heavy viscous, sand fluids

No internal valves to clog or gas lock

Quiet operation

PCPs ADVANTAGES

Simple installation with minimal maintenance costs

Portable, lightweight surface equipment

Low surface profile for visual and height sensitive areas

Can be run into deviated and horizontal wells.

The production rates can be varied with the use of a variable-speed controller with an downhole-pressure sensor.

PCPs DISADVANTAGES

Limited lift capabilities (approximately 7,000 ft. maximum)

Current elastomer temperature limits restricts their use to about 325 F (163 C).

Limited production rates, maximum of 800 m3/d [5,040 B/D].

Chemical attack to the elastomer (aromatics and H2S)

Source: ABB

PCP market

Over 60,000 units in the world

Main markets are Canada and Venezuela

Fastest Growing market

To alleviate problems inherent with the conventional rotating-rod PCP systems (the rotating rods wear and also wear the tubulars), the ESPCPsystem is available.

Because the PCP usually rotates at approximately 300 to 600 rev/min, and the ESP motor rotates at approximately 3,500 rev/min under load, a gearbox is used to reducespeed before the shaft connects to the PCP.

Electrical Submersible PCP

PCP DESIGN EXAMPLE FOLLOWS ..

Subsurface Hydraulic Pumps


Consist of a surface power fluid system, a prime mover, a surface pump, and a downhole jet or piston pump.

Crude oil or water (power fluid) is taken from a storage tank and fed to the surface pump.


The power fluid is controlled by valves at a control station and distributed to one or morewellheads and directed to the downholejet or piston hydraulic pump


Types of installations

In a piston pump installation, power fluid actuates the engine, which in turn drives the Pump, and power fluid returns to the surface with the produced oil, is separated, andis sent to the storage tank.

A jet pump has no moving parts and employs the Venturi principle to use fluid under pressure to bring oil to the surface.

HYDRAULIC LIFT SYSTEM ADVANTAGES

Jet Lift

No moving parts

High volume capability

"Free" pump

Multiwell production from a single package

Low pump maintenance

HYDRAULIC LIFT SYSTEM ADVANTAGES

Piston Lift

"Free" or wireline retrievable

Positive displacement-strong drawdown

Double-acting high-volumetric efficiency

Good depth/volume capability (+15,000 ft.)

HYDRAULIC LIFT SYSTEM DISADVANTAGES

High initial capital cost

Complex to operate

Only economical where there are a number of well

together on a pad.

If there is a problem with the surface system or prime

mover, all wells are off production.

Animations about Hydraulic Lift System

1:06 to 3:00 min Hydraulic Jet Pump

Gas Lift System

Gas Lift

Compressed gas is injected through gas lift mandrels and valves into the production string.

The injected gas lowers the hydrostatic pressure in the production string to reestablish the required pressure differential between the reservoir and wellbore, thus causing the formation fluids to flow to the surface.

A source of gas, and compression equipment is required for gas lift.

Gas Lift The Pros Valves are wireline retrievable Sand travels in tubing, not in valve.

No restriction to flow Wellhead small but compressor large Many wellsone compressor Flexible to changing conditions.Gas is injected between casing

and tubing, and a release valve on a gas lift mandrel is inserted in the tubing above the packer

Gas Lift

The Cons Needs High-Pressure Gas well or Compressor. High initial capital purchase cost. One well may be uneconomical. Viscosity causes problems. Can not achieve low PRBHP

Maintenance intensive

Gas

Lift

Methods of Gas Lift System

Continuous gas lift Reservoir pressure high enough to support a relative

high fluid column Capable of rates of 200 to 60000 BPD

Intermittent gas lift Wells producing relatively low production rates,

usually les than 200 BPD It is injected until the slug reaches the surface and then

the gas injection ceases

Intermittent Gas Lift System

Designing a Gas Lift System

Minimise wellhead back pressure

Optimum Injection gas pressure

Gas flow determined by well performance (inflow and outflow)

Compressor design

Gas dehydration

Downhole Gas lift equipment

Minimise wellhead back pressure, avoid:

No wellhead chokes.

Small flowlines.

Undersized gathering manifolds.

High compressor suction pressure.

The injection-gas pressure at depth must > the flowing producing pressure at the same depth.

Less downhole equipment for higher injection-gas pressures: the 800-psig design reaches only the depth of 4,817 ft and requires seven gas lift valves. The 1,400-psig design uses only four gas lift valves to reach the full depth of the well at 8,000 ft.

Optimum compression pressure around 2000 psig.

Use of ANSI Class 900 pipe (2160 psig working pressure)

Reciprocating compressors are used more often than centrifugal compressors in gas lift operations because of their flexibility under changing conditions and applicability to small flowrates.

Compressor Design

Gas dehydration

Gas is water-saturated at producing conditions

Water vapour should be removed to avoid: Formation of liquids (slugs) Hydration formation and blocking of lines/valves, etc

Gas dehydration: Absorption (Triethylene glycol, TEG): 7 lb/MMSCF Adsorption (desiccants solids)

Downhole Gas lift equipment

Consists of gas lift valves and mandrels in which the valves are placed. The API Spec. 11V1 covers the manufacture of these devices.

A gas lift valve is normally removed or installed by wireline operations without pulling the tubing.

Depth of the Top Gas lift Valve

The top gas lift valve should be located at the maximum depth that permits U-tubing the load fluid from this depth with the available injection gas pressure.

Animations about Gas Lift

GAS LIFT DESIGN EXAMPLE FOLLOWS ..

Summary of Artificial Lift

Operating Parameters Rod Pumping PCP Hydraulic

Piston

ESP Gas lift

Typical Operating Depth

(TVD), ft

100 to 11000 2000 to 4500 7500 to 10000 5000 to 10000

Maximum Operating

Depth (TVD), ft

16000 6000 17000 15000 15000

Typical Operating Flow,

BFPD

5 to 1500 5 to 2200 50 - 500 100 to 30000 100 - 10000

Maximum Operating

Flow , BFPD

6000 4500 4000 40000 30000

Typical Operating

Temperature

100 - 350 F

[40-177 C]

75 - 150 F

[24-65 C]

100 - 250 F

[40-120 C]

100 - 250 F

[40-120 C]

Maximum Operating

temperature 550 F

[288 C]

250 F

[120 C]

500 F

[260 C]

400 F

[205 C]

400 F

[205 C]

Artificial Lift Methods - Characteristics and Areas of Application

Operating Parameters Rod Pumping PCP Hydraulic Piston ESP Gas lift

Corrosion handling Good to

Excellent

Fair Good Good Good to

excellent

Gas handling Fair to good Good Fair Fair Excellent

Solids handling Fair to good Excellent Poor Fair Good

Fluid gravity > 8 API < 35 API > 8 API > 10 API > 15 API

Offshore applications Limited Good Good Excellent Excellent

System efficiency 45% - 60% 40% - 70% 45% - 55% 35% - 60% 10% - 30%

Artificial Lift Methods - Characteristics and Areas of Application

Design comparison: Gas Lift Vs ESPData for Gas Lift

S-4S-3S-2S-1Well # 4353Num. of valves

3069.6

)1480(

3223.7

)1490(

2714.4

)1470(

3554.8

)1490(

Setting depth (ft)(valve pressure, psia)

5140.7

)1510(

5604.4

)1525(

4548.1

)1460(

6389.5

)1535(

6595.5

)1625(7432.2

5934.8

)1545(7678.6

7525.2-

6928.9

)1645(-

--7612.1-

Surface injection pressure is 1800 psia

Comparison Well-S4Well-S3Well-S2Well-S1 7750650072005872

ESP depthft

4287537741004200Target Production

STBD

REDA SN 3600, 5.38inREDA SN 3600,

5.38inREDA S5200N, 5.38in REDA GN 5200, 5.13inPump type

13713797132No. of stages

ESP_Inc 540_70240 Hp, 2590 V, 59A

REDA 540_90-0 STD350 Hp, 2700 V,

78.5A

REDA 540-90-0 STD 225 Hp, 2075 V, 64

AREDA 540-91 STD

180 Hp, 2313 V, 47.5AMotor type

61657066Pump efficiency %

83858285Motor efficiency %

3803341939324415Liquid rate, STBD

2240191124932799Oil rate, STBD

41 %- 90 %41 %- 90 %36.6 %- 90 %44 %- 95 %Water cut

limitations

)373 - 700 ( SCF/STB)564 - 870 ( SCF/STB)477 - 650 ( SCF/STB)658 - 730 ( SCF/STBGOR Limitations

0.1 - 0.30.1 - 0.30.1 - 0.30.1 - 0.3Pump wear factor

limitations

Design comparison: Gas Lift Vs ESPData for pumps

Production Comparison with Gas Lift

S4S3S2S1Well #

1218114716572500Natural flow (bbl/day)3110220932623928Gas Lift system (bbl/day)

21.52.51.5Injection gas rate (MMscf/day)

155.392.696.857.2 %of increase

S4S3S2S1Well #

71864310521401Natural flow (bbl/day)

1831.8130320682200Gas Lift system (bbl/day)

155.392.696.857.2 %of increase

Total liquid production comparison

Oil production comparison

Total production, bbl/d

Well-S4Well-S3Well-S2Well-S1

1218114816602502Natural flow

3803341939324091ESP

212.23 %197.82 %136.87 %63.51 %Increase of production %

Oil production, bbl/d

Well-S4Well-S3Well-S2Well-S1

71864310521401Natural flow

2240191124932594ESP

211.98 %197.20 %136.98 %85.15 %Increase of production %

Production Comparison with ESP

Profit after 6 monthsWell-S4 Well-S3 Well-S2 Well-S1 Bbl Price 100$

$152,200$126,800$144,100$119,300ESP Profit per day

$27,396,000$22,824,000$25,938,000$21,474,000Revenues for 6 months

835,000835,000835,000835,000Total Costs

$26,561,000$21,989,000$25,103,000$20,639,000ESP Profit

$51,900$66,000$101,600$79,900Gas Lift Profit per day

$9,342,000$11,880,000$18,288,000$14,382,000Revenues for 6 months

281,750274,250289,250274,250Total Costs

$9,060,250$11,605,750$17,998,750$14,107,750Gas Lift Profit

Total Cost for ESP & Gas Lift

$0.00$200,000.00$400,000.00$600,000.00$800,000.00

$1,000,000.00

Well-S1 Well-S2 Well-S3 Well-S4

$

Gas Lift CostESP Cost

Comparison

Profit ESP vs. Gas Lift after 6 months

$0.00$5,000,000.00

$10,000,000.00$15,000,000.00$20,000,000.00

$25,000,000.00$30,000,000.00

Well-S1 Well-S2 Well-S3 Well-S4

ESP profitGas Lift profit

References

Petroleum Engineering Handbook, Volume IV Production Operations Engineering Joe Dunn Clegg, Editor

Artificial Lift R & D Council (ALRDC), http://www.alrdc.com

Gabor Takacs, Sucker-Rod Pumping Manual, 2003.

Centrilift Submersible Pump Handbook, Sixth Edition

Gabor Takacs, Gas Lift Manual 2005

References

Basic Artificial Lift, Canadian Oilwell Systems Company Ltd.

Oil and Gas Production Handbook, ABB 2006

Artificial Lift Design For Oil Wells, United Arab Emirates University

http://www.slb.com/content/services/artificial/index.asp

Gabor Takacs, Electrical Submersible Pumps Manual 2009

Recommended Practice for Sizing and Selection of ESP Installations, API RP 11S4, 2002.

Weatherford International Ltd., 2005

Documents

Art Lift Slide Show