34th Gas-Lift WorkshopSingapore

February 7 - 11, 2011

This presentation is the property of the author(s) and his/her/their company(ies).It may not be used for any purpose other than viewing by Workshop attendees without the expressed written permission of the author(s).

Riser Base Gas Lift to Control Severe Slugging

Lilia Naveira, Petroleum Engineer

Ivan Noville, Petroleum Engineer

Authors:

Feb. 7 - 11, 2011 2011 Gas-Lift Workshop 2

Topics

ObjectiveSevere slugging phenomenonImpact on the well production and processing plant

Case analysis: Well A and Well B

Conclusions

Well data Simulations of the slug behavior Mitigation actions Riser Base Gas Lift (RBGL)Simulation results using RBGL

Introduction

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Objective

Analyze the problem

Use transient simulations

Propose actions

Minimize huge oil production loss caused by severe slugging phenomenon and reduce the impacts of

these instabilities on the processing plant

What can we do?

On the processing plant

Increase in shutdown frequency

Increase in gas volume to the flare

Damage to equipment

Low performance of fluid separation topside

Feb. 7 - 11, 2011 2011 Gas-Lift Workshop 4

Impacts of severe slugging

Decrease in oil production

On production

Oil pre-heater

Severe slugging phenomenon

Low liquid and gas velocities:

Pipe Geometry:Drop in production rates Increase in watercut Decrease in GOR Limitations of gas lift injection

Downward inclination + upward riser

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Case analysis

Well A

Well B

Feb. 7 - 11, 2011 2011 Gas-Lift Workshop 7

Well data

3800 ft

9300 bpd 8200 bpd

4700000 scft/d

Well B

RDO 5/16"

7063000 scft/d

Venturi 5/16"

High liquid

flow rate

Gas lift

injection rate

Well A

Gas lift

valve model

Deep

water depth3200 ft

-3000

-2500

-2000

-1500

-1000

-500

0

0 1000 2000 3000 4000 5000 6000 7000 8000 9000

Well B

-3000

-2500

-2000

-1500

-1000

-500

0

0 1000 2000 3000 4000 5000 6000 7000

Well A

Feb. 7 - 11, 2011 2011 Gas-Lift Workshop8

Well data

620 ft300 ft∅ Flowline = 6” ∅ Flowline = 8”

Length: 5300m (17300 ft)

WCT (%)µ (cP)

GOR (scft/bbl) 443

60111,73

Length: 6400m (21000 ft)

3271

12

Pressure (psi)

ProductivityIndex (bpd/ psi)

WCT (%)µ (cP)

GOR (scft/bbl)

5041,9483

3336

53

Pressure (psi)

ProductivityIndex (bpd/ psi)

Fluid

Reservoir

Pipe

geometry

1400

1600

1800

2000

2200

2400

2600

2800

3000

3200

0 4 8 12 16 20 24 28 32 36

Time (hours)

Dow

nhol

e P

ress

ure

(psi

)

0

100

200

300

400

500

600

700

800

900

Pre

ssur

e - T

opsi

de c

hoke

(psi

)

Downhole pressure (PI) Downhole pressure (OLGA)

Upstream topside choke (PI) Upstream topside choke (OLGA)

0

7000

14000

21000

28000

35000

42000

49000

56000

63000

70000

7 9 11 13 15 17 19 21

Time (hours)

Liqu

id fl

ow ra

te (b

pd)

Well A: OLGA ResultsSlug BehaviorWell A: OLGA X PI ProcessBook

Feb. 7 - 11, 2011 2011 Gas-Lift Workshop 9

Feb. 7 - 11, 2011 2011 Gas-Lift Workshop 10

Well A: Transient Simulation (OLGA)

0

500

1000

1500

2000

2500

3000

15 17 19 21 23 25 27 29 31 33 35

Time (hours)

Do

wn

ho

le P

ress

ure

(p

si)

0

500

1000

1500

2000

2500

3000

Pre

ssu

re -

To

psi

de

Ch

oke

(p

si)

Downhole pressure (PI) Downhole pressure (OLGA) Topside upstream choke (PI) Topside upstream choke (OLGA)

0

7000

14000

21000

28000

35000

42000

49000

56000

63000

70000

7 9 11 13 15 17 19 21Time (hours)

Liqu

id fl

ow r

ate

(bpd

)Well B: OLGA ResultsSlug behavior

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Well B: OLGA x PI ProcessBook

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Well B: Transient Simulation (OLGA)

Increase in gas lift

injection rate

Topside choking

Topside slugging choke

Feb. 7 - 11, 2011 2011 Gas-Lift Workshop13

Mitigation actions

Decreases oil production

Very difficult to adjust the control logic

High Cost: 2 flowlines + subsea pump

Riser base gas lift

Subsea separation

Smaller diameter insertion

Others

More usual

New options

Pigging

problems

Requires additional compressed gas volume

Depends on the gas lift valve model installed

Feb. 7 - 11, 2011 2011 Gas-Lift Workshop 14

0

2500

5000

7500

10000

12500

15000

17500

20000

22500

25000

27500

30000

31 33 35 37 39 41 43 45 47 49 51 53 55

Time (hours)

Liqu

id fl

ow r

ate

(bpd

)

4696850 scft/d (GLV injection) 7062933 scft/d (RBGL injection)7839855 scft/d (RBGL injection)

Well A: Transient Simulation RGBL (OLGA)

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Well A: Transient Simulation RGBL (OLGA)

Feb. 7 - 11, 2011 2011 Gas-Lift Workshop 16

0

5000

10000

15000

20000

25000

30000

35000

40000

45000

50000

55000

60000

65000

70000

10 12,5 15 17,5 20 22,5 25 27,5 30

Time (hours)

Liqu

id fl

ow ra

te (b

pd)

7062933 scft/d (GLV injection) 5297199 scft/d (RBGL injection)7062933 scft/d (RBGL injection)

Well B: Transient Simulation RGBL (OLGA)

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Well B: Transient Simulation RGBL (OLGA)

Feb. 7 - 11, 2011 2011 Gas-Lift Workshop 18

Why did RBGL perform better for well B?

↓ Downstream

Wellft ft

3837 3215

well A well B

Water depth

Liquid flow rate

fluctuation in reservoir

0

500

1000

1500

2000

2500

3000

3500

4000

0 8000 16000 24000 32000 40000 48000 56000 64000 72000 80000

Liquid flow rate (bpd)

Pres

sure

(psi

)

∆Q1 ∆Q2

∆P

Why did RBGL perform better for well B?

Well

bpd/psi bpd/psi

53 12Productivity

Index

Well BWell A

A

B

Well flowing

pressure fluctuation

Feb. 7 - 11, 2011 2011 Gas-Lift Workshop 20

Why did RBGL perform better for well B?

0

1000

2000

3000

4000

5000

6000

7000

8000

9000

10000

11000

12000

13000

14000

15000

16000

17000

18000

10 15 20 25 30 35 40 45 50

Time (hours)

Liqu

id fl

ow ra

te in

rese

rvoi

r (bp

d)

Well B Well A

Feb. 7 - 11, 2011 2011 Gas-Lift Workshop 21

Why did RBGL perform better for well B?

Well

Flowline Diameter (in) 6 8

Flowline Lenght (ft) 17300 21000

Flowline volume (ft3) 3397 7330

well A well B

Feb. 7 - 11, 2011 2011 Gas-Lift Workshop 22

Conclusions

RBGL installation may effectively minimize:

Success depends

on parameters:

Well water depth

Well productivity index

Production flowline diameter

Others

Severe slugging problems

Requires additional compressed gas volume

Requires equipments installation

Feb. 7 - 11, 2011 2011 Gas-Lift Workshop 23

Conclusions

Importance of transient simulations

Find the best scenario to use new technologies

First is necessary to: Model the complete system

Reservoir + tubing / Flowline + riser

The complete system contribuites to have a better understanding of the production

system interaction

Feb. 7 - 11, 2011 2011 Gas-Lift Workshop 24

Obrigado! Thank You!

Email: lilianaveira@petrobras.com.br

Feb. 7 - 11, 2011 2011 Gas-Lift Workshop 25

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Feb. 7 - 11, 2011 2011 Gas-Lift Workshop 26

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