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.
Design of an ESP installation
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.
Design of an ESP installation
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.).
Design of an ESP installation
Surface power supply parameters:
Primary voltage available at the wellsite. Frequency of the power supply. Available power supply capacity.
Design of an ESP installation
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%.
ESP Design Example (cont)
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 ==
ESP Design Example (cont)
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
=
=
ESP Design Example (cont)
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 ==
ESP Design Example (cont)
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/)( ===
ESP Design Example (cont)
And
Therefore:
695.1035.172 MscfVFG ==
[ ] McfbblPTfZBg /62.27.1014/)160460(85.004.5/)04.5( =+==
BGPDMcfbblMcfVIG 181/62.269 ==
ESP Design Example (cont)
The flow of water is
Therefore:
25501725181644 BFPDBWPDBGPDBOPDVt =++=
%7100*)2550/181(100)/( % === VtVgasfreeof IG
BWPDXwQdVw 172575.02300 ===
% of free gas at the pump intake
ESP Design Example (cont)
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
ESP Design Example (cont)
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()( ==
ESP Design Example (cont)
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 ==
ESP Design Example (cont)
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
Design of an ESP installation
Design of an ESP installation
Design of an ESP installation
Design of an ESP installation
Design of an ESP installation
Progressing Cavity Pumps (PCPs)
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.
Progressing Cavity Pumps (PCPs)
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
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.
Subsurface Hydraulic Pumps
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
Subsurface Hydraulic Pumps
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