Analysis of Gas Lift Transient Effects Henry Nickens Adam Ballard BP - Houston

Analysis of Gas Lift Transient Effects

Henry NickensAdam Ballard

BP - Houston

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Gas Lift Instability

• Steady-state methods for gas lift design and analysis do not capture the pressure/temperature transients that inevitably occur in an operating gas lifted well.

• Transient well response occurs during:

– Unloading the well

– Well shut-down

– Normal well operation (e.g., tubing/casing heading, multi-pointing)

– Well kick off or shut-down with CT

• This paper presents analysis of gas lift instability for two design cases:

1. To aid in selection of optimum tubing size (5.5 in vs 7 in)

2. To determine hydrate formation in CT gas lift after shut-down

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Gas Lift Instabiliy

• OLGA2000 version 4.01 was used to model the wells

– transient multi-phase flow simulator

– developed by Scandpower

• Two cases are studied:

1. New well design to determine

– optimum tubing size

– Effect of injection rate, orifice size and wellhead pressure

2. CT gas lift shut-down to determine time to hydrate formation

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Gas Lift Instability – Case 1

A new well is to be drilled. Steady-state analysis shows that gas lifting 7-inch tubing gives potentially much greater production than 5.5-inch tubing.

What is the expected stability of the well for the range of expected injection rates, production rates and water cuts?

The onset of instability (severe slugging) was calculated as a function of injection rate and water cut to define the expected operating window for instability.

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Well Characteristics – Case 1

• 5 ½“ or 7 “ ERD

• Production Fluid– 860 scf/stb GOR– 33 oil API– 0.663 gas SG– 20000 ppm water salinity

• Gas lift– gas injection valve at 16000 feet MD (0.8125” ID)– 1595 psia gas injection pressure– 0.7 gas SG

0 5000 10000 15000 20000

Horizontal Distance (feet)

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OLGA Model – Case 1

• Model setup

– WELL module used for inflow

– constant P boundaries at tubing head and casing head

– choke controlled for constant gas rate

– gas lift orifice ID of 0.8125”

Annulus Tubing

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Comparison of OLGA with Steady- State Simulators Case 1

0 1 2 3 4 5 6 7 8

Gas Injection Rate (mmscf/d)

OLGAPROSPERPIPESIM

5.5" ERD Well0% Watercut1595 psia Injection 232 psia THP2538 psia Pres

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Sample Result – Case 1 – 5.5”

0 1 2 3 4 5 6 7 8 9

1595 psia Injection 232 psia THP2538 psia Pres

0% Watercut

40% Watercut

95% Watercut

OLGA - Solid LinesPROSPER - Dashed Lines

60% Watercut

80% Watercut

Transient FlowUnstable Flow – Onset of Slugging

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Sample Result – Case 1 – 7”

0 1 2 3 4 5 6 7 8 9

7" ERD Well1595 psia Injection

232 psia THP2538 psia Pres

0% Watercut

40% Watercut

OLGA - Solid LinesPROSPER - Dashed Lines

95% Watercut

80% Watercut

60% Watercut

Unstable Flow – Onset of Slugging

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Conclusions - Case 1 - Tubing ID

• The injection pressure did not have a significant impact on the stability of the flow.

• For both 7” and 5.5” tubing, flow is stable at watercuts below 80-90%

• The 5.5” tubing is more stable at higher watercuts.

• At 4 mmscf/d injection rate,

– the 5.5” tubing is stable up to 80% WC for both 1595 and 2030 psia injection pressures

– the 7” tubing is unstable at 80 % WC with 2030 psia injection pressure

• At 8 mmscf/d injection rate

– 5.5” tubing is stable for at all watercuts

– 7” tubing is unstable at 95 % watercut.

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Effect of Injection Rate on Stability

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2 MMscf/d Injection Rate - Case 1

0 5000 10000 15000 20000 25000 30000 35000

Time (s)

) OLGAPROSPER

5.5" ERD Well95% Watercut2 mmscf/d Gas Rate1595 psia Injection 232 psia THP2538 psia Pres

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0 5000 10000 15000 20000 25000 30000 35000 40000 45000

Time (s)

OLGAPROSPER

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0 5000 10000 15000 20000 25000 30000 35000 40000 45000

Time (s)

OLGAPROSPER

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Effect of Injection Rate on Stability

0 5000 10000 15000 20000 25000 30000 35000

Time (s)

OLGAPROSPER

0 5000 10000 15000 20000 25000 30000 35000 40000 45000

Time (s)

OLGAPROSPER

0 5000 10000 15000 20000 25000 30000 35000 40000 45000

Time (s)

OLGAPROSPER

Severe Slugging Intermittent Slugging Steady Flow

(low rate) (mid rate) (high rate)

2 MMscf/d 4 MMscf/d 8 MMscf/d

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0 50 100 150 200 250 300 350 400

Wellhead Pressure (psia)

)Effect of Wellhead Pressure on Stability

4 mmscf/d injection rate95% Watercut

Steady State

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Effect of Wellhead Pressure on Stability – Case 1

Intermittent SluggingRegion

Surging Region Severe SluggingRegion

OscillatingRegion

S-SRegion

0 50 100 150 200 250 300 350 400

requency

Slug FrequencySlug Size

4 mmscf/d gas rate95% Watercut

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Steady Surging (Case #1)

0 5000 10000 15000 20000 25000 30000 35000

Time (s)

WHP - 15 psiaWHP - 75 psia

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Intermittent Oscillating (Case #1)

0 5000 10000 15000 20000 25000 30000 35000

Time (s)

WHP - 200 psia

WHP - 270 psia

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Oscillating Severe (Case #1)

0 5000 10000 15000 20000 25000 30000 35000

Time (s)

WHP - 300 psia

WHP - 370 psia

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Effect of Wellhead Pressure on Stability – Case 1

Intermittent SluggingRegion

Surging Region Severe SluggingRegion

OscillatingRegion

S-SRegion

0 50 100 150 200 250 300 350 400

requency

Slug FrequencySlug Size

SS/Surge Flow Intermittent Slugging Severe Slugging

(lo WHP) (medium WHP) (higher ID)

Effect of Orifice Port Size on StabilitySteady Flow Intermittent Slugging Severe Slugging

(small ID) (medium ID) (large ID)

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Effect of Orifice Port Size – Case 1

0 5000 10000 15000 20000 25000 30000 35000 40000 45000

Time (s)

0.25" Valve0.5" Valve1" Valve1.5" Valve

Choked at ~2 mmscf/d

2334 stb/d5654 stb/d5312 stb/d3553 stb/d

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Gas Lift Instability – Case 2

CT gas lift for a deepwater GoM well is proposed.

In addition to stability issues, hydrate formation is a major concern.

OLGA is used to calculate the pressure and temperature transients during the CT gas lift shut-down period and the resultant effect on fluid temperature and hydrate formation.

Hydrate Cool-Down Time

Time after shut-in when the first hydrate is formed anywhere in the system.

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Well Characteristics - Case 2

• 4“ production tubing

• Production Fluid– 1455 scf/stb GOR– 29.2 oil API– 0.734 gas SG– 0 ppm water salinity

• Gas lift– 2 3/8” OD coiled-tubing gas lift at 5921 feet MD – four-port (½“ ID) bit– constant gas injection rate– 0.7 gas SG

0 1000 2000 3000 4000 5000 6000

Horizontal Distance (feet)

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OLGA Well Model – Case 2

• Model setup

– WELL module used for inflow

– constant source boundaries at tubing head and casing head

– Orifice ID = 1”

Coiled-Tubing Annulus

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Well Head Pressure - Case 2

0 5 10 15 20 25 30 35

Head P

3000 stb/d

5000 stb/d

10000 stb/d

50% Watercut

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Gas Injection Pressure - Case 2

0 5 10 15 20 25 30 35

Required I

3000 stb/d

5000 stb/d

10000 stb/d

50% Watercut

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Well Head Temperature - Case 2

0 5 10 15 20 25 30 35

Head T

3000 stb/d

5000 stb/d

10000 stb/d

50% Watercut

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Cooldown Time to Hydrates - Case 2

0 5 10 15 20 25 30 35

3000 stb/d

5000 stb/d

10000 stb/d

50% Watercut

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Conclusions

Transient flow calculation is a valuable tool for gas lift design and analysis to evaluate non-steady effects

– Gas Lift stability analysis

• Effect of injection gas rate, orifice size and wellhead pressure

• Needs improved valve models for unloading, multi-pointing, stability related to unload valve problems

– Gas Lift flow assurance studies

• Cooldown to hydrate formation

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Analysis of Gas Lift Transient Effects Henry Nickens Adam Ballard BP - Houston

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