Conventional Plunger Lift Well’s - ALRDC · 8th European Conference on Gas Well Deliquification 14-16 October 2013, Hampshire Hotel, Groningen, The Netherlands Conventional Plunger

8th European Conference on Gas Well Deliquification

14-16 October 2013,

Hampshire Hotel, Groningen, The Netherlands

Conventional Plunger Lift Well’s

Dynamic IPR and Gas Flow Rate

Determined from dP/dT,

plus Historical Method for Gas Wells

Lynn Rowlan

[email protected]

Determine Plunger Lift

Gas Volume Produced per Cycle

Problem: • Compute the total cumulative standard volume of gas

produced from well during the plunger cycle.

Solution: • From Tubing Intake Depth to Surface Know Volume of

Tubing and Casing Annulus

• Use Gas Free Liquid to Reduce Tubing Volume

• Determine the mass of gas in the tubing and casing annulus as a Function of Pressure and Temperature at all Times During Cycle

• Use Mass Balance to Allocate Gas out of Formation, into/out of Casing Annulus, Tubing, and Down Flow Line

2 Oct 14-16, 2013 2013 European Conference on Gas Well Deliquification

Account for Mass of Gas in Tubing and

Casing Annulus at any Time During Cycle

Total number of moles in tubing is given by:

ZRT

PVn

ZnRTPV

Where V = capacity of tubing/casing (cu. Ft) less liquid volume

And P, T= average pressure and temperature in tubing

Tubing and Casing Annulus are Divided into Short Segments.


Flow rate Qin, SCF/D

P (bottom)

Cas & Tub, psia

Pt, Pc

psia

Flow rate

Qout, SCF/D

T

u

b

i

n

g

D

e

p

t

h

Motor Valve

Flow Line

How is Gas Flow Rate Determined?

Formation

For 1 Complete Cycle

Well Model Allocates

Gas between:

1. Casing Annulus, Tubing, Out

of Formation, and Down Flow

Line

2. Assume that no gas is

temporarily stored in the

formation

3. Gas flow from the formation

is directly related to PBHP.

Vol Tubing

Vol Casing

Where’s the

Plunger

Liquid

Height


Flow rate Qin, SCF/D

P (bottom)

Cas & Tub, psia

Pt, Pc

psia

Flow rate

Qout, SCF/D

T

u

b

i

n

g

D

e

p

t

h

Motor Valve

Flow Line

How is Gas Flow Rate Determined?

Formation

• Gas that flows down the Flow Line

is equal to the gas that flows out

of the Formation.

• OR the total system pressure

increases if all of the gas

produced from the formation does

not flow down the flow line.

• OR the system pressure

decreases if MORE gas flows

down the flow line than is

produced from the formation.

Vol Tubing

Vol Casing

Where’s the

Plunger

Liquid

Height

5

For a Complete Cycle

Oct 14-16, 2013 2013 European Conference on Gas Well Deliquification

Gas Volumes/Flow Rates:

Formation, Casing, Tubing, Gas Slips by Plunger, and Flow Line

A) Valve Closes (Shut In Begins)

1) Plunger Hits Liquid

2) Plunger on Bottom

B) Valve Opens (Unloading Begins)

3) Liquid Arrives

4) Plunger Arrives

C) Valve Closes (Shut In Begins)

Simple Mass

Balance Used to

Calculate Gas

Volume Over

Each of These

Intervals

Note: Cycle’s Pressure at

Beginning [A] is Greater

than Pressure at End [C]

[A] [C]

Shut In Unloading

Afterflow

Rate = Change in Volume per Time Step Data Acquisition on 3 Channel 30Hz Frequency or Greater

Gas Volumes/Rates

Calculated Using Tubing,

Casing Pressure and

Acoustic Signals

7

Casing Pressure Acoustic Signal Tubing Pressure


Gas Volumes/Rates are

Calculated Differently over

Each of these Intervals

Well Information Important to the Accuracy of

Calculated Gas Volumes and Flow Rates

1. Average Joint Length

• Fall Velocity, Gas Specific Gravity,

Acoustic Velocity, and Plunger Depth

2. Tubing & Casing Sizes and Weight /foot

• Gas Volumes and Gas Flow Rates

3. Tubing Intake Depth

• Gas Volumes, Gas Flow Rates, and

Calculated Pressures


120.0

140.0

160.0

180.0

200.0

220.0

240.0

260.0

280.0

300.0

320.0

-0.3

-0.2

-0.1

-0.1

-0.0

0

0.1

0.1

0.2

0.000 13.889 27.778 41.667 55.556 69.444

During Shut-in Gas flowing from Formation is

Captured in the Tubing/Casing Annulus

Tubing Pressure Increases Due to

Gas being stored in Tubing Annulus

Casing Pressure Increases Due to

Gas being stored in Casing Annulus

Gas Volume Integrated over Tubing Length for Tubing & Casing Areas

[A]

[1] [2]

[B]

Gas Free Liquid

Height subtracted

from the Available

Storage Volumes


Gas Volume Flowing from Tubing/Casing Annulus

Depend on Pressures & Gas Free Liquid Height

Shut-in Tubing Pressure

Determines Gas Stored in Tubing

Shut-in Casing Pressure Determines

Gas Stored in Casing Annulus

[A] [4] [B]

Gas Free Liquid

Height Adjust

Gas Volumes

[C]

[B-4] Gas Above

Plunger goes

Down Flow Line


0

2000.0

4000.0

6000.0

8000.0

10000.0

12000.0

2.274 16.163 30.052 43.941 57.829

Tubin

g G

as V

olu

me - (scf)

Elapsed Time - minutes

Casin

g G

as V

olu

me - (s

cf)

Sum Casing Annulus+Tubing Gas Volumes During

Shut-in to Determine Gas Flow From Formation

[B]

20.0

40.0

60.0

80.0

100.0

120.0

140.0

160.0

2.274 16.163 30.052 43.941 57.829

Form

ation G

as F

low

Rate

s - (M

scf/D

)


240.0

272.0

304.0

336.0

368.0

400.0

Botto

m H

ole

Pre

ssure

- (psi)

[A]

Gas Flow Rate is the Change in

Gas Volume over Each Time Step

IPR for the Well is Flow

Rate as a Function of

Flowing BHP

Oct 14-16, 2013

Plot Calculated Gas Flow Rate from Formation

versus FBHP at End of Tubing During Shut-in

Could Fit Measured Data

to Determine Well’s Inflow

as a Function of Flowing

Bottom Hole Pressure

12 Oct 14-16, 2013 2013 Appalachian Basin Gas Well Deliquification Workshop, Marietta, Ohio

Curve Fit thru Measured Data Determines

Equation of Mscf/Day as a Function of FBHP


Use Dynamic Inflow Performance Curve to

Calculate Gas Flow Rates When Valve Open

During Shut-in Period

Calculated Gas Flow Rate

from Formation versus

FBHP at End of Tubing

Can calculate Flow Rate From Formation for Any Flowing BHP.

Curve Fit thru Measured

Data Determines Well’s

Inflow Performance From

Shut-in to Max Flow Rate

14

Predicted Static

Predicted Q-Max


20.0

40.0

60.0

80.0

100.0

120.0

140.0

160.0

180.0

2.274 16.163 30.052 43.941 57.829 71.718 85.607

Form

ation G

as F

low

Rate

s - (M

scf/D

)


220.0

256.0

292.0

328.0

364.0

400.0

Botto

m H

ole

Pressure - (p

si)

Use Dynamic Inflow Performance Curve to

Calculate Gas Flow Rates When Valve Open

During Period [B-C]

Calculate Gas Flow

Rate from Formation

Use Well’s IPR Determined From Shut-in Period To Calculate

Flow Rate From Formation for Any Flowing BHP.

[B] [C] [A]

Valve

Open

15 2013 European Conference on Gas Well Deliquification

0

20.0

40.0

60.0

80.0

100.0

120.0

140.0

160.0

180.0

2.274 16.163 30.052 43.941 57.829 71.718 85.607

Form

ation G

as F

low

Rate

s - (M

scf/D

)


0

1600.0

3200.0

4800.0

6400.0

8000.0

Form

atio

n G

as V

olu

me - (s

cf)

Gas Volume Flowing from Formation:

During [A-B] Gas Stored in Tubing/Csg. Annulus

During [B-C] Gas Volume is from IPR and FBHP

[B] [A]

Flow Rate

Function of

Flowing BHP

[C]

Cumulative

Gas Volume

Flowing from

Formation

16 JOct 14-16, 2013 2013 European Conference on Gas Well Deliquification

During Unloading Gas Volume Slipping by the Plunger equals:

Gas volume leaving Casing + Gas volume flowing from formation –

Gas Volume Remaining in Tubing when plunger arrives at surface

[B] [A]

Zero Gas Slips by Plunger

During [A-1-2-B and 4-C] [C]

Gas Volume

Slips Past

Plunger

During

Unloading

[B-3 3-4]

[4]


[B-3] Plunger comes to surface as all gas above Plunger

goes down Flow line + gas that slips by the plunger

[3-4] Only Gas Down Flow Line is gas slipping by plunger

[B] [A]

Gas Down Flow Line [A-1-2-B] is

Zero Because the Valve is Closed [C]

[4-C] Plunger is held at surface.

Gas Down Flow Line equals

decrease in casing volume +

decrease in tubing volume +

gas that flows out of the

formation (IPR)

[4] [3]


Gas Per Cycle Produced Down Flow Line During:

Unloading (11min 26sec) 4.5 Mscf w/ Max 1400 MscfD

Afterflow (9min 17sec) 3.23 Mscf w/ Max 635 MscfD

[B]

High Gas Flow Rate When Valve is Open

7.73 Mscf/Cycle of Gas Produced

[C] [4] [3]

Turner

Critical Rate

Valve Open

19 JOct 14-16, 2013 2013 European Conference on Gas Well Deliquification

Gas Produced During Cycle:

Gas Flow (Formation) = 7.432 Mscf/Cycle ~ 121.9 Mscf/D

Gas Flow (Flow Line) = 7.733 Mscf/Cycle ~ 126.9 Mscf/D

[B]

Gas Continually Flows From Formation

[C] [A]

Gas Flows Down Flow

Line When Valve Open

Valve

Open


Gas Production Current = 100 Mscf/D (Read off Chart)

Gas Flow from Formation = 122.0 Mscf/D

Gas Flow Down Flow Line = 126.9 Mscf/D

Gas In Gas Out ?

Tested 8 Different Plungers in 1 Well for Gas Flow Rate During Cycle

• Had stable flow characteristics

• Effort made to not change the plunger control settings

• Normal functioning standing valve

• Tubing Intake of 8080.71 ft.

• One set of perforations 8121.92-8151.44 feet

• 2 3/8” Tubing, 5.5” Casing, and No packer

• Produced 0.63 BPD water and no condensate

• Able to run on timer control in order to control the flowing environment


100.0

120.0

140.0

160.0

180.0

200.0

220.0

-1.5

-1.0

-0.5

0

0.5

1.0

1.5

3.676 21.037 38.398 55.759 73.120 23

1.87% Error in Calculated vs Measured Gas Volume

End of Cycle

Flow Line = 5548 scf

Valve Opens

@ 68.638 Minutes

Flow Line = 0 scf

Plunger Arrives

@ 76.396 minutes

Slips by Plunger = 384.9

scf Flow Line = 2622 scf

Company B dual pad seal – Complete Cycle

Elapsed Time - Minutes

Measured vs Calculated Gas Volumes for 1 Cycle


Company A Dual Pad – Gas Volumes

Gas Volume (scf/cycle) Calculated VERSUS

Measured during cycle for all 8 plungers:

• Average Error 9.9% of the measured scf/cycle.

• Maximum Error of 16%

• Minimum Error of 1.9%

25

Error =14.4%

Oct 14-16, 2013 2013 Appalachian Basin Gas Well Deliquification Workshop, Marietta, Ohio

Plunger Lift Gas Volumes Determined During Cycle

Determine Plunger Lift Gas Rates During Cycle

Gas flowing into well

Tested Gas

Production =

265 MCF/D

358

psi

FBHP = 1080.6 psi

Closed Valve 2.5 Min. to

Determined Gas Flow

Rate and % Liquid

dP/dT Correction

8636’ Gaseous Height

Da, Adjusted Gas Free Gaseous

1615’

Gas

Free

11261’

EOT

SPE 14254 – Acoustic

Determination of

Producing Bottomhole

Pressure

Iterates to Determine:

•Gas Flow Rate

• Adjusted Liquid Level

Gas Flow Rate Equations

Example of Derived Well Performance

Curves Based on PBU during Shut-in


Kees Veeken by Email 8/14/2013 2:19 AM

Conclusions 1. Gas Flow Rates

• Reasonably accurate (need more data)

• Expect some difference between EFM

• Gas Stacking can occur, but Chart and EFM

can be over-ranged

2. Dynamic IPR Calculations

• Gas Flow Rate and FBHP determined During

Shut-in Period Used to Calculate Well’s IPR

• Varying Flow Rates versus Bottom Hole

Pressure can be used to Calculate Formation

Flow During the Entire Plunger Lift Cycle



33

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Documents

Conventional Plunger Lift Well’s - ALRDC · 8th European Conference on Gas Well Deliquification 14-16 October 2013, Hampshire Hotel, Groningen, The Netherlands Conventional Plunger