Plunger Lift Systems Bumper Spring - ALRDC - · PDF fileCommonly Used Operating Parameters for...

© 2001 Weatherford. All rights reserved.

Plunger Lift Systems


Plunger Lift SystemsApplications

• Unload wells that continue to load up with produced wellbore fluids.

• Reduce fallback in wells being produced by intermittent gas lift.

• Increase production in wells with emulsion problems.

• Enhance production in high gas/liquid ratio wells.

• Clean tubing ID in wells experiencing paraffin problems.

Lubricator

Catcher

Solar Panel

Controller

Dual “T” Pad

Plunger

Bumper

Spring


Plunger LiftSystem Advantages

• Requires no outside energy source; uses well’s energy to lift

• 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

Lubricator

Catcher

Solar Panel

Controller

Dual “T” Pad

Plunger

Bumper

Spring


Plunger LiftSystem Limitations

• Specific GLRs to drive system

• 1000m3 gas/m3 liquid per 1000m.

• Example

• Well Depth 3000m

• Gas 10000 m3/day

• Water 3 m3/day

Solution 3000 m means we would need around 3000m3 gas per m3 of liquid. This well has 3333 (10000/3)

• Low-volume potential maximum of 30 m3/day in typical applications.

• Ability to build pressure.

• Indication of pressure available to lift needs to be 1.5-2 times flowing tubing pressure usually available in 1-2 hours.

• Example

• Flowing Tubing Pressure 10 bar

• SITP – 30 Bar

• 2 Hour Build Pressure 20 Bar

Likely Good Candidate – If the 2 Hour build was 13 bar and SITP was 15 bar it would likely be a poor candidate

Lubricator

Catcher

Solar Panel

Controller

Dual “T” Pad

Plunger

Bumper

Spring

© 2001 Weatherford. All rights reserved. © 2001 Weatherford. All rights reserved.

Ideal Conditions

• Casing and Tubing Communicated

• Flowing wellhead pressure below 20 bar

• Consistent ID tubing from top of perforations to wellhead

• Wellhead Consistent

• No Solids Production

• Limited Wax/Paraffin Production

• Casing works as an immediate energy source

• Velocity can be established with little build pressure

• Plunger is efficient with minimal places to hang up

• Plunger travels all the way to surface

• Plunger does not have anything to hang up on.

• Plunger can “keep up” and clear some wax.


Non Ideal Conditions

• Casing and Tubing Not Communicated

• Flowing wellhead pressure above 20 bar

• Non-Consistent ID tubing from top of perforations to wellhead

• Wellhead Consistent

• Some Solids Production

• Excessive Wax/Paraffin Production

• Energy from lift has to come from perforations

• Velocity can be established however more build pressure necessary.

• Modified Plungers or Multi-Stage required.

• Sleeves may need to be applied.

• Careful evaluation during wireline needed to ensure that the plunger will not hang up

• Plunger may require continuous injection of Paraffin Dispersants in conjunction with plunger to keep up.


Typical Gas Well Production Decline Curve

Top

Normal Decline

Cu

mu

lati

ve

Pro

du

ction

Incre

ase

Loading

Deviation

PlungerInstalled

Time

We

ll P

rod

uc

tio

n

–Optimum to return well original production decline

–Inflow performance relationship (IPR) curve can be used but typically requires specialized IPR as the well will be unstable.


Life Cycle of Well


Life Cycle of Well – As a plunger

1. Well is flowing above critical with all flow in mist flow; no liquid gradient at any time.

2. Well begins to bubble and slug (usually high-speed bypass candidate if +15 ft/s or 5 m/s velocity is available).

3. Well begins to have difficulty maintaining seal as a result of velocity below 15 ft/s but above 10 ft/s or below 5 m/s and above 3 m/s (usually good application for padded bypass plunger).

4. Well requires shut-in time to build pressure to maintain velocity of plunger as gas falls below 10 ft/s or 3 m/s (quick-drop application).

5. Well requires build time (conventional plunger lift applicable as fall time not important).

6. Well requires substantial build time (high efficiency seals require more fall time but have a better seal).


Theory of Plunger Lift: Operation

1. Plunger acts as interface between liquids and gas energy.

2. When surface control parameters are met, sales valve opens and exhausts pressure to create differential pressure across plunger.

3. Differential pressure then lifts liquids and plunger to surface.

4. Sensors record plunger’s arrival, sales time starts.

5. When sales time parameters are met, surface valve closes; plunger goes to off cycle and falls.

6. Cycle is repeated.

Plunger lift: method of artificial lift that uses well’s gas energy as the prime mover of liquids that have caused loading


Plunger Lift Equipment Overview


Equipment Overview

• Controller: Electronic-based system with control parameters for opening and closing motor valves

• Transducer: Electronic device that emits an electronic signal to be converted within controller to engineering units

• Motor Valve: Diaphragm-operated device controlled by controller to open/close sales/tank line

• Lubricator/Catcher: Uppermost stopping point for plunger; acts as shock absorber; catcher retrieves plunger for inspection

• Arrival Sensor: Magnetic device strapped around lubricator to detect plunger arrivals

• Bumper Spring: Shock absorber at plunger’s deepest stopping point

• Plunger: Pig-type device that provides seal inside tubing to deliver fluid and gases to surface with differential pressure


Bumper Springs/Standing Valve

• Set with Slick line

• Free fall set from surface – Not Recommended

• Ball and seat option

• Wireline retrievable

• H2S service available


Collar Stop and Tubing Stop

• Type A tubing stop

• Type F collar stop

• Used when tubing is open ended

• Wireline set

• Wireline retrievable


Lubricators

Cushions plunger upon arrival into wellhead to prevent damage

• Single or dual outlet

• Catcher option

• Sensor mount

• Threaded outlets

• Spring-loaded cap and striker pad


Accessories- Common between Vendors

• Motor valves

• Sensor switch

• Solar panels

• Strap-on sensors

• Drip pot w/ regulators

• Control pilots

• Pressure reducing

• Differential control

• Gas filters


Controllers

Controller options:

• On/Off

• On/Off with Arrival Recognition

• Self adjusting on Arrival time only

• Pressure Based

• Complete Automated Systems

Computerized means of opening and closing motor valve based on programmed responses or sets of parameters (sequence of events)


History of Plunger Lift Control

Evolution of plunger lift control• Time cycle control

• On time -- off time

• Time cycle with plunger arrival recognition• On time -- sales time -- off time

• Auto-adjust time cycle• Adjust time settings by reacting to failure• Plunger traveling -- too fast, too slow, none

• Pressure based Stand Alone control• Operates on the pressure build of the well and on current

operating conditions optimizing every cycle based on the wells capability and the systems capacity.

• Pressure based Auto-Adjust w/ Communications• Central based communications provide-pressure based

control as well as adjustable settings from a central Host.© 2001 Weatherford. All rights reserved.

Simple On/Off High Low

• These controllers can be used as our On/Off Controller with On, Off, Sales, Plunger Fall and Shut-In settings.

• Also used as a High/Low Controller

• The upgrade for this controller also has an Auto-Tune Feature (Next Slide)


Auto Tune Option - Controllers


Typical Plunger Installation Basic On/Off or AutoAdjust


Pressure Controlled System


Pressure Based Control

Controller Information

• 6 Analog Inputs (1-5V or 4-20 mA) Currently used for Tubing, Casing, Line, and Differential pressure as well as Temperature.

• Digital Inputs (Plunger Arrival switch, Murphy switch, tank float switch etc.)

• Digital Outputs (3 currently used on pulse valve operation)

• Certified to Class 1 Div 2 Class A,B,C,D or non-hazardous location

• Communicates using Modbus or similar.


Some Typical On Pressure Limit Control

1. Tubing pressure > or = on pressure limit

2. Casing pressure > or = on pressure limit

3. Tubing – line > or = on pressure limit

4. Casing – line > or = on pressure limit

5. Foss and Gaul Calculations

(looks for tubing pressure to exceed a set

point)

(looks for casing pressure to exceed a set

point)

(looks for tubing pressure to build to a set

point above line pressure)

(looks for casing pressure to build to a set

point above line pressure)

(looks for casing to reach a calculated

value)

Commonly Used Operating Parameters for Plunger Lift Well Control

Using Flow and Pressure-operated Control System

Initiate on cycle for plunger lift when:


Some Typical Off Pressure Limit Control

Initiate off cycle for plunger lift when:

1. Plunger has arrived (used on oil wells)

2. Casing pressure < or = off pressure limit (looks for casing to fallbelow a set pressure)

3. HW < or = off pressure limit (looks for flow rate to fall below a setdifferential in inches of water)

4. Flow Rate (Sometimes a calculated Turner Rate)

5. Casing-tubing > or = off pressure limit (looks for differentialbetween casing and tubing to increase)

6. Casing To Tubing Sway looks for the casing and tubing pressure to start moving apart from each other.

7. Casing to Line > or = off pressure limit (looks for differential between casing and line pressure to increase)


Normally Recorded Information in Pressure Control

Basic Pressure Control

• On and off condition based on pressure differential between any one or two pressure measuring instruments.

• Arrival data for 50 previous plunger cycles including time/date stamped On and Off pressures and plunger arrival time.

• Communication ready using Modbus Protocol for Automation-ready installation.

• Ability to poll a flow computer using Modbus Protocol and make this data available back at host.


Advance Pressure Controllers w/ Communication

Foss and Gaul Calculation

• A calculation in the controller to consistently perform a Foss and Gaul calculation establishing the proper moment to kick the well off.

• This calculation is a relationship accounting for fluid load, surface pressure, casing size, tubing size, frictions and depth.

• This calculation allows the opportunity to completely compensate for changing line pressure as well as changes in inflow.


]][)(7.14][1)[((min))(

a

talflhtpreqc

A

AALPPPP

K

DAFP

++++++=

• Pc(req)=The “required” casing pressure. Before the tubing is opened, which allows the plunger and liquid slug to begin moving up the tubing, the casing pressure must be equal to Pc(req),or greater. If the casing pressure were any lower, the plunger would stall before reaching the surface.

• D = depth to end of tubing (feet) (vertical)

• K = term for gas friction in the tubing

• Pp = pressure required to lift weight of plunger (psi)

• Pt(min) = flow line pressure; also the minimum tubing pressure (psi)

• Plh = pressure required to lift one barrel of fluid (psi/bbl)

• Plf = frictional losses between the liquid slug and the tubing (psi/bbl)

• L = load size (bbls)

• Aa = capacity of the annulus (bbls/ft)

• At = capacity of the tubing (bbls/ft)

• AF = adjustment factor for inflow of well.

Foss and Gaul Calculation


Different Situations Different Pressures

A B C DA B C DA B C DA B C D

Situation A:

5 ½” Casing, 2 3/8” Tubing, 0.15 m3 of fluid, (78 m controller recognizes based on 800 kPa differential), 690 kPa line

Situation B:

5 ½” Casing, 2 3/8” Tubing, 0.3 m3 of fluid, (156 m controller recognizes based on 1600 psi differential), 690 kPa line

Situation C:

4 ½” Casing, 2 3/8” Tubing, 0.15 m3 of fluid, fluid load 800 kPa differential, 690 kPa line

Situation D:

7 ½” Casing, 2 3/8” tubing, 0.15 m3 of fluid, fluid load 800 kPa differential, 690 kPa line


Different Situations Different Pressures

A B C DA B C DA B C DA B C D

Situation A:

Required Casing Pressure is 3088 kPa.

Situation B:

Required Casing Pressure is 4895 kPa.

Situation C:

Required Casing is 3523 kPa.

Situation D:

Required Casing pressure is 2778 kPa.

This is strictly a Mechanical Calculation. In order to compensate for inflow the adjustment factor will have to be used.


Load Factor

Another Common Lift Algorithm is Load Factor

(Casing-Tubing)/(Casing-Line) < or = 50%

Example

Casing 200 kPa Casing 300 kPa

Tubing 100 kPa Tubing 200 kPa

Line 50 kPa Line 50 kPa

Solution 66% Not ready Solution 40% Ready


Casing-Tubing Sway

Casing Sway Algorithm

• In order to completely optimize a casing-communicated well that produces minimal fluid loads it is sometimes necessary to flow the well below critical velocity until fluid begins to accumulate to a point to where a significant load has been achieved.


Casing-Tubing Sway

Cycle without Casing/Tubing Sway

0

200

400

600

800

1000

1200

0 20 40 60 80 100 120 140 160 180 200

TimeP

res

su

re/F

low

Ra

te

Casing Tubing Differential Line Pressure Flow Rate

Loading Begins

Well severely loaded


Casing-Tubing Sway

Cycles with Casing Sway

0

200

400

600

800

1000

1200

Tim

e

Time

Pre

ss

ure

/Flo

w R

ate

Casing Tubing Differential Line Flow Rate

Point where Casing and Tubing are

closest 105 psi diff.30 PSI greater difference


Casing-Tubing Sway

1. Identify Point where Casing and Tubing get as close to each other as possible.

2. Identify when they start to move apart from each other.

3. Allow the pressures to move a set amount apart to ensure that the well can not unload on it’s own again.

4. Shut in once the minimal point plus


Pressure Based communicated devices

AGA 3, 8 Gross Method 2 Calculation

• Ability to calculate flow rate from the differential across an orifice plate with static pressure and temperature included.

• Data stored includes: Current hour, last hour, last day and all days up to the last 30.

• Also stores Cumulative Day data


Data Logging/Tank Level Measurement

Data Logging Transfer

• Data logger of all pressures measured configured based on customer need and communication needs.

Tank Level Capability

• Support tank gauges for fluid level and if applicable oil height, water height and lower tank temperature.


Pressure based communicated controllers

Emergency Shut Down Condition

• Additional safety and environmental concerns have been noted in the newest controllers, these will take any form of a digital input (tank float, Murphy Switch, etc) and shut-in the well. The user selects if the well returns to service either Manually or Automatically when the condition is relieved.

• Manual: This function is used if the producer has a policy to check wells when shut-downs occur before bringing them back on.

• Automatic: If the producer has the digital inputs used solely for pieces of equipment that can be routinely worked on and brought back into service once the problem has been solved. © 2001 Weatherford. All rights reserved.

Persistent Set Times

• Timers available that will begin to count down once the controller has reached it’s designated on or off trigger and will force it to remain in the current state until the set-point has been reached for a designated amount of time.

• Benefits

• Well is slugging and giving low differential or flow readings

• Well is dumping and gas being used for dumping process temporarily slows down flow

• High/Low is activated momentarily while separator is dumping

• Transducer momentarily gives a false reading


Pressure based communicated devices

Controllers can be configured in the

field or from the central host


Chart of Controller Types

Optimization done with all pressure data for maximum production and continuous operation based on current situation

Optimization done with all pressure data for maximum production and continuous operation based on current situation

Optimization keeps up with changes in build pressure and line pressure but does not take all pressure into account

Optimization keeps up with slight changes in well condition

As long as well is operating no problems, changes in well condition result in additional time being required

Pumper Friendly

Optimization done with all pressure data for maximum production and continuous operation and flow measurement

Optimization done with all pressure data for maximum production and continuous operation

Optimization done based on 2 pressures

Some Optimization done based on previous run

None, Optimization done w/ Pumpers

Optimization

54321Difficulty to Learn (1-

5)

Adjustments made on all current pressure data and while calculating flow data

Adjustments made on all current pressure data

Adjustments made on Current Pressure comparison

Adjustments Made on Arrival Time

Basic On/Off Cycle w/ Sales

Options

$8K$5K$4K$1.5K$1.5KCost w/ Inputs

Complete AutomatedComplex PressureSimple PressureAuto-AdjustOn/Off


Plunger Applications


Life of a Plunger Well

A-Well Flowing Above Critical

B-Well flowing just below critical (High Speed Spiral Continuous Flow)

C-Well flowing below 15 ft/s 5 m/s Padded Continuous Flow

D-Well flowing below 10 ft/s or 3 m/s Conventional

E-Low Reservoir pressure and inflow Seal very Important, consideration for Staging Plungerlift


High-Speed Continuous-Flow Plungers

Description:

• Solid-ring seal

• Large amount of flow through center for maximum falling velocity

• Trip rod at surface to separate ball from sleeve, or open valve to allow flow through.

• 1.24-in2 cross-sectional bypass (compared to 0.60-in2

on padded bypass)

Applications:

• Wells that have just fallen below critical velocity but still have +15 ft/s or 5 m/s velocity available

• Single-well compression (low suction pressures, high velocity, no downtime necessary)

• Very Wet Wells (more trips than possible with conventional plungers)

• Excellent range of usage on low line-pressure wells

RapidFloTM


Where does this happen?


Plunger Installation # 4: (installed 11-June)

0

50

100

150

200

250

300

350

400

4/2

4/2

004

5/1

/2004

5/8

/2004

5/1

5/2

004

5/2

2/2

004

5/2

9/2

004

6/5

/2004

6/1

2/2

004

6/1

9/2

004

6/2

6/2

004

7/3

/2004

mcfd

0

100

200

300

400

500

600

700

800

psig

well daily production

average mcfd pre-install

average mcfd post-install

casing pressure

Plunger Installation #4: (installed 11-June)

0

50

100

150

200

250

300

350

400

4/2

4/2

004

5/1

/2004

5/8

/2004

5/1

5/2

004

5/2

2/2

004

5/2

9/2

004

6/5

/2004

6/1

2/2

004

6/1

9/2

004

6/2

6/2

004

7/3

/2004

mcfd

0

15

30

45

60

barr

els

per day

daily fluid production wellhead mcfd © 2001 Weatherford. All rights reserved.

Padded/Brush Continuous-Flow Plungers

Description:

• Bypass-type plungers (allow flow through the plunger) with pad seal

• May have internal trip rod or trip rod in lubricator to trip valve

• 0.60-in2 cross-sectional bypass (compared to1.24-in2 on high-speed bypass)

Applications:

• 10 to 15-ft/s (3-5 m/s) velocities for continuous flow

• High fluid producers with quick build times for quick trip application

• Can be run at slightly higher line pressures than high speed plungers because of increased seal at lower velocities


Where does this happen?


Example of Application

Well successfully operating a conventional 2 3/8” Pad x Pad Plunger to 350 psi line pressure however there appeared to be additionalgas production possible if well unloaded continually.


Conventional Plungers



Description:

• Pad Plungers

– Metal/metal seal

– High efficiency, even after cycling for months

• Brush Plungers

– Fiber seal

– Initially efficient seal

• Solid-Ring Plungers

– Turbulent seal

– Least-efficient seal

Applications:

• Pad Plungers

– Very low solid movement(sand, scale)

– Maximum seal necessary tomove fluid

• Brush Plungers

– Sand movement

– Some cases necessary for efficiency

• Solid-Ring Plungers

– Scales application

– Dry-trip potential

– Poor monitoring in field (no moving parts)


Strengths: Pad Plungers

• Highly efficient sealas a result of actual contact with tubing walls at all times

• Will adjust for tight spots yet maintainseal at full OD

• Seal enables efficient moving of fluidat lower velocities

Limitations: Pad Plungers

• Require maintenance to avoid breakage

• Moving parts may cause potential for fishing job




Strengths:

• Brush Plungers

– Initial efficiency very high (most available in conventional)

– Ability to move sand, fibers, allow for sand to be in fibers without sticking plungers

• Solid Rings

– No moving parts, nothing to break, no pads to stick

– Ability to “chip” at, and move through, scale

Limitations:

• Brush Plungers

– Wear very quickly

– Quick wear results in losses in efficiency

– Expensive and difficult to rewrap

• Solid Rings

– Poor seal, even initially

– +15-ft/s velocity must be sustained to maintain turbulent seal


New Plunger TechnologyProgressive Plunger Lift


Where is it Used (What makes a Good Candidate)

• Primarily used in wells that have GLR’s below what is necessary to lift a conventional plunger.

• Generally wells that barely make the required gas for lifting a plunger from bottom with the required fluid loads.

• Wells that shut in on arrival due to significant inflow of fluid during lift cycle.

• Field Trials indicate that it decreases lift gas by .

• Also used in wells which are depleted to the point that they no longer can lift using available casing pressure builds.

• Wells that have previously been considered Rod Pump Candidates.

• Wells with Multiple String Sizes


What is it?

• By adding a second set of plunger equipment and “staging” your lift cycle you essentially produce the well with two plunger systems.

• The system includes from bottom to surface

1. A typical bottom hole bumper spring

2. A solid ring plunger for the bottom stage

3. An ILA (see right) made up of two bumper springs (one facing up/one down) a sealing component, a check valve and a tubing stop.

4. Another plunger to lift for the upper stage (usually a double pad)

5. A Lubricator to receive the upper plunger.


Where is it Used (What makes a Good Candidate)

• Primarily used in wells that have GLR’s below what is necessary to lift a conventional plunger system.

• Generally wells that barely make the required gas for lifting a plunger from bottom with the required fluid loads.

• Wells that shut in on arrival due to significant inflow of fluid during lift cycle.

• Field Trials indicate that it decreases lift gas by 1-3 Mcf per Barrel.

• Also used in wells which are depleted to the point that they no longer can lift using available casing pressure builds.

• Wells that have previously been considered Rod Pump Candidates.


Determining Set Depth

• As a general Rule ILA is set at 65% of the total depth from surface to PSN.

• Actual optimal depth is can also be calculated.

1. Establish approximate gradient of well

2. Use pressure at 65% as a start point as the pressure for the lower stage and line pressure as upper stage and complete Foss and Gaul Calculations.

3. Adjust Depth as necessary to establish the same gas requirement for the upper and lower stage using fine adjustments.

Once these Calculations are done the well can be identified as a good candidate and the install depth can be chosen.


Pressure vs. Depth

Pressure and In-situ gas velocity vs Depth Analysis for Douglass 6-4

Gas Condensate WaterRate Rate Rate WGR CGR(MMSCF/day) (STB/day) (STB/day) (STB/MMSCF) (STB/MMSCF)0.115 1.000 20.000 173.910 8.700

10200

8925

7650

6375

5100

3825

2550

1275

0

Tru

e V

ert

ica

l D

ep

th (

ft)

8007006005004003002001000Pressure (psia)

108.757.56.2553.752.51.250In-situ gas velocity (ft/sec)

Pressure: Qg,prod = 0.115 MMSCF/dayIn-situ gas velocity: Qg,prod = 0.115 MMSCF/day

Pressure=386Psi

Depth = 6,360'


Example Well Conditions and Calculation Results


• Well producing 70 Mcf/day with 10 bbls of water. 4 ½” Casing 2 3/8” Tubing to 12350 feet (1.97 E3/day w/ 1.6 m3 of water 3740 m)

• GLR is 7 MCF per barrel of water (1.2 E3m3/m3)

• 50 Psi (345 kPa) Line Pressure

• Requires casing pressure build of 775 psi (5340 kPa) to get an arrival to line pressure.

• Uses 16 Mcf (0.45 E3)in order to lift the 2 bbl (0.322 m3) slug. (1.3 E3m3/m3)

• The 16 Mcf (0.45 E3) used to lift brings in another 2.25 bbls (0.36 m3) behind it. Next lift requires even more pressure and even more gas. Well can not keep up, fluid is left behind over all production is reduced.

Possible Solutions

a) Vent Valve-Reduce Head pressure however vent production gas away.

b) Consider a Progressive Plunger System (Staged)


Venting To Surface

• Reduces head pressure to nearly nothing.

• Result is that it only takes 14 Mcf (0.282 E3) to lift the 2 bbls (0.32 m3) of fluid with only 600 psi (4137 kPa) Casing pressure.

• With only 14 Mcf (0.282 E3) being used to lift, only another 2 bbls (0.32 m3)come in behind

Negative

• Much of the 14 Mcf will be vented away resulting in lower total gas production


Installed

at 8350

ft/2530 m

0.32 m3 of water

5343 kPa Casing pressure to lift

0.45 E3m3/cycle

0.16 m3/cycle

5240 kPa Casing Pressure

0.15 E3m3/cycle


Progressive Plunger System

Results

• The GLR necessary to lift this well drops from 1.3 E3m3/m3 down to 1 E3m3/m3

• Since the plunger system now only use 1 E3m3/m3 and the well actually produced 1.2 the system can keep up.

• Casing Pressure needed to lift is reduced from 775 psi to 580 psi. (5343 to 4000 kPa)

0.11 m3/cycle

4000 kPa

0.11 E3m3/cycle


Progressive Plunger System

Results

• More Cycles with less fluid per cycle resulting on more total production.

• Well can keep up with fluid as it is delivered from the formation.

• Casing Pressure is reduced therefore reducing back pressure and increasing inflow.

• Well does not need to vent (all gas is paid for)

• Cycle’s are more regular


Champ 1-30

0

5

10

15

20

25

1/1/0

51/1

5/05

1/29/0

52/1

2/05

2/26/0

53/1

2/05

3/26/ 0

54/9

/05

4/23/0

55/7

/05

5/21/0

56/4

/05

6/18/ 0

57/2

/05

7/16/ 0

57/3

0/05

8/13/0

58/2

7/05

9/10/0

5

BO

PD

, B

WP

D

0

50

100

150

200

250

300

350

400

450

Ga

s M

CF

/Da

y,

CP

Oil Water Gas CP

Installed Progressive Plgr. 3/28/05


This well struggled continually on a conventional system producing between 100-200 Mcf/day and making between 5 and 15 bbls/day largely due to the packer, with dual stage it produces around 400 Mcf/day with 30 bbls/day


Example of a Relieve Pressure Valve

• Valves can be used to hold pressure but if pressure is added above the valve fluid can be pushed back down.

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