Gas Well Deliquification Workshop Sheraton Hotel, Denver, Colorado February 17 – 20, 2013 Kees Veeken – Shell (NAM) Rahel Yusuf – SPT Group Model the Effectiveness.

Gas Well Deliquification WorkshopSheraton Hotel, Denver, Colorado

February 17 – 20, 2013

Kees Veeken – Shell (NAM)

Rahel Yusuf – SPT Group

Model the Effectiveness of Pump and Plunger by Transient Multi-Phase Flow Simulation

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

2

Contents

• Objectives

• Transient Vs Steady State

• Pump modeling

• Plunger modeling


3

Objectives

• How much back pressure is introduced by the flowing wet gas column in the presence of a pump that removes liquids from the bottom of the well ?

– The outcome determines the effectiveness of a pump and defines the best ways of operating a pump

• What is the effectiveness of a plunger that travels up to the subsurface safety valve but does not cover the short distance between subsurface safety valve and wellhead ?

– The outcome determines the requirement for a second plunger to dewater the top section


4

Transient Vs Steady State• Pump intake pressure sits in between too high steady

state VLP and too low dry gas VLP

– How effective is downhole separation?

– How steady is production and how much gas will enter pump ?

• Plunger action is transient in nature

– Will slug of liquid be able to bridge “gap” ?

10

20

30

40

50

60

70

0 50 100 150 200 250 300

FBH

P (b

ara)

Gas Rate (e3 m3/d)

Modified Gray Gray Beggs & Brill Petex 4 SRTCA

FTHP=20 barg


5

Pump Modeling Parameters

• 5.5” tubing + 5” liner down to 3040 m

• Pump on 1.5” CCT @ 3020 m

• Inflow across 2770-3040 m with 3% below pump

• Darcy inflow A=80 bara/(e3m3/d)

• Reservoir Pres=35-55-65-75 bara

• WGR=23-7, CGR=10 m3/e6m3

• Wellhead pressure = 9 bara

Constant mass pump rate for liquid and gas i.e. keeps pumping in case of gas ingress

GasLiquidPower


6

OLGA Liquid Loading Point

5

15

25

35

45

55

65

75

0 10 20 30 40 50 60 70 80

FBH

P (b

ara)

Gas Rate (e3 m3/d)

IPR – Pres=69 baraLL – OLGA Qmin=58e3 m3/d

VLP – Modified GrayVLP - Gray

VLP – Cullender-Smith


7

Pres=55 bara – No PumpingGas rate (e3 m3/d)

Pressure @ pump intake (bara)Holdup @ pump intake (-)

Liquid in wellbore (m3)


8

Pres=55 bara – Pumping @ 1 m3/d

Gas rate (e3 m3/d)Pressure @ pump intake (bara)

Holdup @ pump intake (-)Liquid in wellbore (m3)

• Stable holdup @ pump intake: gassy liquid (8 Sm3/d gas)


9


Significant holdupacross bulk of wellbore


10


Liquid holdup increasespump intake pressure


11


• Oscillating holdup @ pump intake: gassy liquid or gas




12


Holdup is sluggingup and down wellbore


13


Pump intake pressureoscillates


14


• Oscillating holdup @ pump intake: gassy liquid or gas




15

Pumping Operating Points

2

1

4 21.5

1

0.5

0.51

0

5

15

25

35

45

55

65

75

0 10 20 30 40 50 60 70 80

FBH

P (b

ara)

Gas Rate (e3 m3/d)

IPR – Pres=75/65/55/35 baraVLP – Modified Gray

VLP – GrayVLP – CS (dry & wet)

OLGA – Pumping (m3/d) & LL


16

Pumping Summary

• Back pressure due to liquid holdup is unavoidable

• Magnitude increases as Q increases– Insignificant at low enough Q but significant at higher Q as

downhole separation becomes less effective

– Back pressure does not increase with higher WGR!

– Production penalty increases as inflow improves!

• Gas ingress into pump depends on pump rate and location of pump intake relative to inflow profile – Pump off triggers slugging and large gas ingress

Further explore influence of pump location, liner size and deviation on back pressure and gas ingress


17

Plunger Modeling Parameters

• 3.5” tubing to 1169 m, 5”x4.5” liner to 1310 m

• Plunger between “launch” @ 1145 m and “trap” @ 0-330 m (SSSV @ 102 m)

• Inflow @ 1310 m, A=5.2 bara/(e3m3/d)

• Pres=12-18 bara, WGR=10-88 m3/e6m3, CGR=0 m3/e6m3

• Wellhead pressure = 8 bara

• 3.5” tubing plunger weight = 7.5 kg, zero leakage, SV or 3 bara BPV

• 9 plunger cycles 2 hr flow, 1 hr shut-in

17

Tu

bin

gW

ellb

ore

PL

Trap

LaunchSV


18

Field – No Plunger, Close to LL

THP (barg)Gas Rate (Nm3/d)

• 1 hr flow, 0.5 hr shut-inWYK4-FI-4-32-1

26013

NM3/D

WYK4-PI-4-32-1

7.8435

BARG

WYK4-TI-4-32-1

15.807

DEG.C

WYK4-FI-4-32-1.INT

18995

NM3/D

CALCULATED FLOW

FLOWLINE TO WELLHEAD PRESSURE

TEMPERATURE

CALCULATED FLOW

26/05/2012 00:00:0025/05/2012 00:00:00 24.00 hours

WYK-32

0

10000

20000

30000

40000

50000

60000

70000

80000

90000

1.E+05

0

20

0

100

-50000

50000

FTHP (bara)Gas Rate (Nm3/d)


19

Field – Plunger 11 hrs ON, 1 hr OFF



14926

NM3/D

WYK4-PI-4-32-1

6.9256

BARG

WYK4-TI-4-32-1

20.681

DEG.C

WYK4-FI-4-32-1.INT

6514.1

NM3/D

CALCULATED FLOW


TEMPERATURE

CALCULATED FLOW

14/06/2012 18:00:0014/06/2012 15:00:00 3.00 hours

WYK-32

0

10000

20000

30000

40000

50000

60000

70000

80000

90000

1.E+05

0

20

0

100

-50000

50000TT~20 min (excessive)

VEL~52 m/min (170 ft/min)ON period too long



20

Field – Plunger 2 hrs ON, 1 hr OFF



0.0000

NM3/D

WYK4-PI-4-32-1

10.965

BARG

WYK4-TI-4-32-1

15.695

DEG.C

WYK4-FI-4-32-1.INT

13692

NM3/D

CALCULATED FLOW


TEMPERATURE

CALCULATED FLOW

28/06/2012 00:00:0027/06/2012 21:00:00 3.00 hours

WYK-32

0

10000

20000

30000

40000

50000

60000

70000

80000

90000

1.E+05

0

20

0

100

-50000

50000TT~5 min

VEL~209 m/min (690 ft/min)



21

WGR=88 m3/e6m3, Pres=17.516.5bara

Gas rate (Sm3/d)Cumulative Liquid (m3)

Liquid in tubing (m3)Liquid in wellbore (m3)

Qmin=29e3m3/d @ Pres=16.9bara


22

8

9

10

11

12

13

14

15

16

17

18

0 5 10 15 20 25 30 35 40

FBH

P (b

ara)

Gas Rate (e3 m3/d)

OLGA Liquid Loading Points

IPR – Pres=14.3-16.9 baraVLP – Modified Gray WGR=10-88 m3/e6m3

OLGA LL Points WGR=10-88 m3/e6m3


23

WGR=88, Pres=15, Trap @0, BPV (#8)

THP (bara)Gas rate (Sm3/d)

Liquid in Tubing (m3)Liquid in Wellbore (m3)Plunger Velocity (m/s)Plunger Position (m)

TT~6.5 minVEL~161 m/min

(530 ft/min)


24

WGR=88, Pres=15, Trap @0, SV, 23.9 hr

Holdup Tubing (-)Pressure Tubing (bara)

Holdup Wellbore (-)Pressure Wellbore (bara)


25





26





27





28

WGR=88, Pres=15, Trap @0, SV, 25.9 hrs






29





30





31

WGR=88, Pres=15, Trap @0, BPV (#8)




(530 ft/min)


32

WGR=10, Pres=15, Trap @0, SV


Cumulative Liquid (m3)Liquid in Tubing (m3)

Liquid in Wellbore (m3)


33

WGR=10, Pres=15, Trap @0, SV (#8)




(1150 ft/min)


34

WGR=10, Pres=14, Trap @0, SV (#8)




(1050 ft/min)


35

WGR=10, Pres=13, Trap @0, SV (#8)



TT~4 minVEL~260 m/min

(850 ft/min)


36

WGR=10, Pres=12, Trap @0, SV (#4)



TT~5 minVEL~209 m/min

(690 ft/min)


37

WGR=88, Pres=15, Trap @0, BPV





38






39






40






41

8

9

10

11

12

13

14

15

16

17

18

0 5 10 15 20 25 30 35 40

FBH

P (b

ara)

Gas Rate (e3 m3/d)

With Plunger – Operating Points

IPR – Pres=14.3-16.9 baraVLP – CS WGR=11-88 m3/e6m3

– LL WGR=11-88 m3/e6m3

O – WGR=11, Trap=0 – WGR=88, Trap=0

– WGR=88, Trap=102


42

Plunger Summary

• Transient multi-phase flow model produces credible results and provides insight into influence of well parameters on plunger performance

• Plunger needs to travel to top of tubing to deliver maximum value i.e. liquid slug cannot bridge large “gap”

• Plunger introduces back pressure proportional to WGR which can limit applicability in prolific wells– Gas production during upward travel must deliver minimum

plunger velocity and will diminish as slug size increases

Further explore influence of plunger launch position, wellbore (plus annulus) volume, inflow performance and plunger ON/OFF schedule


43

Copyright

Rights to this presentation are owned by the company(ies) and/or author(s) listed on the title page. By submitting this presentation to the Gas Well Deliquification Workshop, they grant to the Workshop, the Artificial Lift Research and Development Council (ALRDC), and the Southwestern Petroleum Short Course (SWPSC), rights to:

– 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.– Place it on a CD for distribution and/or sale as directed by the

Workshop Steering Committee.

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.


44

Disclaimer

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The Artificial Lift Research and Development Council and its officers and trustees, and the Gas Well Deliquification Workshop Steering Committee members, and their supporting organizations and companies (here-in-after referred to as the Sponsoring Organizations), and the author(s) of this Technical Presentation or Continuing Education Training Course and their company(ies), provide this presentation and/or training material at the Gas Well Deliquification Workshop "as is" without any warranty of any kind, express or implied, as to the accuracy of the information or the products or services referred to by any presenter (in so far as such warranties may be excluded under any relevant law) and these members and their companies will not be liable for unlawful actions and any losses or damage that may result from use of any presentation as a consequence of any inaccuracies in, or any omission from, the information which therein may be contained.

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Gas Well Deliquification Workshop Sheraton Hotel, Denver, Colorado February 17 – 20, 2013 Kees Veeken – Shell (NAM) Rahel Yusuf – SPT Group Model the Effectiveness.

Documents

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gas gas rate e3 m3d

effectiveness of pump