dynamic ipr and gas flow rate determined for conventional ... - 5 - presentation... · gas well...

Gas Well Deliquification Workshop

Sheraton Hotel, Denver, Colorado

February 17 – 20, 2013

Dynamic IPR and Gas Flow Rate Determined for Conventional Plunger Lift Well

Lynn Rowlan

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 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

Feb. 17 – 20, 2013

2 2013 Gas Well Deliquification Workshop Denver, Colorado

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.

Feb. 17 – 20, 2013


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

Feb. 17 – 20, 2013 4 2013 Gas Well Deliquification Workshop Denver, Colorado

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


For a Complete Cycle

Gas Volumes/Rates are Calculated

Differently over Each of these Intervals

[A] Valve Closes,

Shut-in Begins

and Tubing

Pressure Starts

Increasing

1. Plunger hits

Liquid

2. Plunger on

Bottom

[B] Valve Opens,

Unloading Begins

3. Liquid Arrives,

Tubing Pressure

at Minimum

4. Plunger Arrives,

After-flow begins

Tubing Pressure

Maximum Spike

[C] Valve Closes,

Cycle Repeats

[A] 1 2 [B] 3 4 [C]

Casing Pressure

Acoustic Signal

Tubing Pressure

Feb. 17 – 20, 2013


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

Acquired Plunger Lift Data Data Acquisition on 3 Channel 30Hz Frequency or Greater

Gas Volumes/Rates

Calculated Using Tubing,

Casing Pressure and

Acoustic Signals

Rate = Change in

Volume per Time Step

Feb. 17 – 20, 2013


Casing Pressure Acoustic Signal Tubing Pressure

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

Feb. 17 – 20, 2013


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


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


0

2000.0

4000.0

6000.0

8000.0

10000.0

12000.0

2.274 16.163 30.052 43.941 57.829

Tu

bin

g G

as

Vo

lum

e -

(s

cf)

Elapsed Time - minutes

Ca

sin

g G

as

Vo

lum

e - (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

Fo

rma

tio

n G

as

Flo

w R

ate

s -

(M

sc

f/D

)


240.0

272.0

304.0

336.0

368.0

400.0

Bo

ttom

Ho

le P

res

su

re - (p

si)

[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

Feb. 17 – 20, 2013

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

Feb. 17 – 20, 2013 13

2013 Gas Well Deliquification Workshop Denver, Colorado

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

Fo

rm

atio

n G

as

Flo

w R

ate

s -

(M

sc

f/D

)


220.0

256.0

292.0

328.0

364.0

400.0

Bo

tto

m H

ole

Pre

ss

ure

- (

ps

i)

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


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

Fo

rm

atio

n G

as

Flo

w R

ate

s -

(M

sc

f/D

)


0

1600.0

3200.0

4800.0

6400.0

8000.0

Fo

rm

atio

n G

as

Vo

lum

e -

(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


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]

Feb. 17 – 20, 2013


[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


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


For a field reading for this chart:

(line psi 150) x (diff. Psi 12” avg) = pressure extension

Take square root pressure extension.

Take your square root reading X orfice coef. ( 1” = 6.549)

The answer will be a 24 hr flow rate in MCF

Take MscfD and divide by 24 hrs for hourly Flowrate.

Ex 150# x 12” = 1800

Square rt of 1800 = 42.4264

42.4264 (psi extsion) x 6.549 (orfice coef for 1”)= 277.85 MscfD

277.85 MCFD / 24 = 11.57 MCFH

11.57 MCFH x 8 hrs (Total flow time for day) = 92.61 MscfD

92.61 MscfD is the daily rate

Blue pen - Static line pressure (% reading multiply by 1000 = Psi)

(Ex 15% x 1000 = 150psi line psi is 150psi

Green pen – line temperature (% reading multiply by 150 = Deg F)

(Ex 40% x 150 = 60 degrees line temperature is 60 degrees

Red pen - Differential pressure (% reading multiply by 100 = “ H2O.

(Ex 20% x 100 = 20 “ of water column

Quote of the Day:

On a Barton chart

if you have 10

pumpers read it

you will have 10

different volumes.

Red Pen Off Chart

MscfD Flow Rate?

100 – Barton Chart

122 – TWM Formation

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

22 2013 Gas Well Deliquification Workshop

Denver, Colorado Feb. 17 – 20, 2013

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%



Error =14.4%

Plunger Lift Gas Volumes Determined During Cycle

Determine Plunger Lift Gas Rates During Cycle

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

28 2013 Gas Well Deliquification Workshop Denver, Colorado Feb. 17 – 20, 2013

Feb. 17 – 20, 2013 2013 Gas Well Deliquification Workshop

Denver, Colorado 29

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– Display the presentation at the Workshop.

– Place it on the www.alrdc.com web site, with access to the site to be as directed by the Workshop Steering Committee.

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Other use of this presentation is prohibited without the expressed written permission of the author(s). The owner company(ies) and/or author(s) may publish this material in other journals or magazines if they refer to the Gas Well Deliquification Workshop where it was first presented.

Feb. 17 – 20, 2013 2013 Gas Well Deliquification Workshop

Denver, Colorado

30

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dynamic ipr and gas flow rate determined for conventional ... - 5 - presentation... · gas well...

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