Gas Lift Fundamentalscloud1.activelearner.com/contentcloud/portals/hosted3/PetroAcademy/... · To Separator/Stock Tank INJECTION GAS ... Plot objective design gradient or trigger

Virtual Session 2

Gas Lift Fundamentals

Gas Lift UnloadingUsing Multiple Unloading Valves

Gas Lift Fundamentals ═══════════════════════════════════════════════════════════════════════════════════

©PetroSkills, LLC. All Rights Reserved. _________________________________________________________________________________________________________

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Learning Objectives

This section will cover the following learning objective:

Establish well unloading procedures

Casing Pressure and Tubing Pressure Trends during Unloading Process

(13789.5)

(12410.5)

(11031.6)

(9652.6)

(8273.7)

(6894.7)

(5515.8)

(4136.8)

(2757.9)

(1378.9)

(kPa)



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Continuous Flow Unloading

Gas in

To Separator/Stock Tank

Dep

th

Pressure

Tubing PressureCasing Pressure

2500 50001250 3750 62500 7000

2000

4000

6000

8000

10,000

12,000

14,000

0

(609.6 m)

(1219.2 m)

(1828.8 m)

(2438.4 m)

(3048 m)

(3657.6 m)

(4267.2 m)

(8618.4) (17236.8) (25855.3)(34473.7)(43092.2) (48263.3)

(kPa)

Top Valve Open

Second Valve Open

Third Valve Open

Fourth Valve Open

Injection GasChoke Closed

SIBHP


Dep

th

Pressure


2500 50001250 3750 62500 7000

2000

4000

6000

8000

10,000

12,000

14,000

0

(609.6 m)

(1219.2 m)

(1828.8 m)

(2438.4 m)

(3048 m)

(3657.6 m)

(4267.2 m)

(8618.4) (17236.8) (25855.3)(34473.7)(43092.2)

(48263.3)

(kPa)

Gas in

Top Valve Open

Second Valve Open

Third Valve Open

Fourth Valve Open

Injection GasChoke Open


SIBHP



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Dep

th

2500 50001250 3750 62500

Pressure


7000

2000

4000

6000

8000

10,000

12,000

14,000

0

(609.6 m)

(1219.2 m)

(1828.8 m)

(2438.4 m)

(3048 m)

(3657.6 m)

(4267.2 m)

(8618.4) (17236.8) (25855.3) (34473.7)(43092.2)

(48263.3)

(kPa)

Gas in

Top Valve Open

Second Valve Open

Third Valve Open

Fourth Valve Open



SIBHP


Dep

th

Pressure


2500 50001250 3750 62500 7000

2000

4000

6000

8000

10,000

12,000

14,000

0

(609.6 m)

(1219.2 m)

(1828.8 m)

(2438.4 m)

(3048 m)

(3657.6 m)

(4267.2 m)

(8618.4)(17236.8) (25855.3) (34473.7)(43092.2)

(48263.3)

(kPa)

Gas in

Top Valve Open

Second Valve Open

Third Valve Open

Fourth Valve Open



DRAWDOWN

FBHP

SIBHP



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Dep

th

Pressure


2500 50001250 3750 62500 7000

2000

4000

6000

8000

10,000

12,000

14,000

0

(609.6 m)

(1219.2 m)

(1828.8 m)

(2438.4 m)

(3048 m)

(3657.6 m)

(4267.2 m)

(8618.4)(17236.8) (25855.3) (34473.7)(43092.2)

(48263.3)

(kPa)

Gas in

Top Valve Open

Second Valve Open

Third Valve Open

Fourth Valve Open



DRAWDOWN

FBHP

SIBHP


Dep

th

Pressure


2500 50001250 3750 62500 7000

2000

4000

6000

8000

10,000

12,000

14,000

0

(609.6 m)

(1219.2 m)

(1828.8 m)

(2438.4 m)

(3048 m)

(3657.6 m)

(4267.2 m)

(8618.4) (17236.8) (25855.3)(34473.7)(43092.2)

(48263.3)

(kPa)

Gas in

Top Valve Closed

Second Valve Open

Third Valve Open

Fourth Valve Open



DRAWDOWN

FBHP

SIBHP



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Dep

th

Pressure


2500 50001250 3750 62500 7000

2000

4000

6000

8000

10,000

12,000

14,000

0

(609.6 m)

(1219.2 m)

(1828.8 m)

(2438.4 m)

(3048 m)

(3657.6 m)

(4267.2 m)

(8618.4) (17236.8)(25855.3)(34473.7) (43092.2)

(48263.3)

(kPa)

Gas in

Top Valve Closed

Second Valve Open

Third Valve Open

Fourth Valve Open



DRAWDOWN

FBHP SIBHP


Dep

th

Pressure


2500 50001250 3750 62500 7000

2000

4000

6000

8000

10,000

12,000

14,000

0

(609.6 m)

(1219.2 m)

(1828.8 m)

(2438.4 m)

(3048 m)

(3657.6 m)

(4267.2 m)

(8618.4) (17236.8)(25855.3)(34473.7) (43092.2)

(48263.3)

(kPa)

Gas in

Top Valve Closed

Second Valve Closed

Third Valve Open

Fourth Valve Open



DRAWDOWN

FBHP SIBHP



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Dep

th

Pressure


2500 50001250 3750 62500 7000

2000

4000

6000

8000

10,000

12,000

14,000

0

(609.6 m)

(1219.2 m)

(1828.8 m)

(2438.4 m)

(3048 m)

(3657.6 m)

(4267.2 m)

(8618.4) (17236.8) (25855.3)(34473.7)(43092.2)

(48263.3)

(kPa)

Gas in

Top Valve Closed

Second Valve Closed

Third Valve Open

Fourth Valve Open



DRAWDOWN

FBHP SIBHP


Dep

th

Pressure


2500 50001250 3750 62500 7000

2000

4000

6000

8000

10,000

12,000

14,000

0

(609.6 m)

(1219.2 m)

(1828.8 m)

(2438.4 m)

(3048 m)

(3657.6 m)

(4267.2 m)

(8618.4) (17236.8)(25855.3)(34473.7)(43092.2)

(48263.3)

(kPa)

Gas in

Top Valve Closed

Second Valve Closed

Third Valve Closed

Fourth Valve Open



DRAWDOWN

FBHP SIBHP



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Learning Objectives

This section has covered the following learning objective:


Gas Lift Design:Gas Lift Design Techniques, Safety Margins,

Computer Assisted Gas Lift Designs



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Learning Objectives


Identify gas lift design methods

Gas Lift Design Objectives

Allow lift gas to be injected as deeply as possible

Conserve as much injection pressure as possible

Ensure all upper unloading valves are closed after the final point of injection has been reached

Be able to unload the well with available injection pressure regardless of the liquid level in the tubing

Ensure that the operating valve passes the correct amount of gas to achieve the required gas lift gradient

Ensure that the above objectives can be met under present as well as near-future conditions



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Gas Lift Design Steps

1. Collect data

2. Identify tubing sizing and mandrel spec (valve OD)

3. Design mandrel spacing

4. Position the operating valve

5. Position the unloading valves

6. Specify the unloading valve specs (port size and pressure setting)

7. Select the orifice valve port size

8. Validate the design

Gas Lift Well with No Unloading Mandrel

Single GLM

Pressure

Unloading Gradient

Operating Injection Pressure

GL Kick off Pressure

TVD

Perforations



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Gas Lift Design with Unloading Valves (IPO)

1. Gather all data

2. Plot gas lift injection gradient

3. Plot well fluid gradient (starting from Pwf), choosing the proper flowing gradient curve

4. Plot operating valve ∆P using operating casing pressure

5. Plot design gradient or trigger line with safety factor (P1, P2) for valve transfer

6. Use casing pressure safety factor for valve closing

7. Space out mandrels using the available gas lift pressure at depth, the trigger line and kill fluid gradient. Locate the first (kick off) valve and other unloading valves down to operating valve

8. Include dummy valves in the spare mandrels below the operating point

9. Determine unloading valve port size and Ptro

10. Finalize the orifice valve specs and the expected operating casing pressure

Graphical Gas Lift Design (IPO)

SBHP (Pres)

Pressure

TVD

Unloading kill fluid gradient

GL kick off pressure

Operating Casing pressure

FBHP (Pwf)

Expected gradient

Design gradient w/ transfer bias

Operating Depth

Minimum mandrel spacing (Future)

Drawdown



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Gas Lift Design with Unloading Valves (PPO)

1. Gather all data.

2. Plot gas lift injection gradient.

3. Plot well fluid gradient (starting from Pwf), choosing proper flowing gradient curve.

4. Plot operating valve ∆P using operating casing pressure.

5. Plot objective design gradient or trigger line with safety factor (P1, P2). Note that there is some 20-25% safety factor at surface for the trigger line as the valves will close sensing the reduction in tubing pressure. The casing pressure will not be reduced for every mandrel station in case of PPO design.

6. Space out mandrels using the available gas lift pressure at depth, the trigger line and kill fluid gradient. Locate the first (kick off) valve and other unloading valves down to operating valve.

7. Include dummy valves in the spare mandrels below the operating point.

8. Determine unloading valve port size and Ptro.

9. Finalize the orifice valve specs and the expected operating casing pressure.

Graphical Gas Lift Design (PPO)

SBHP (Pres)

Pressure

TVD

Unloading gradient

GL kick off pressureOperating Csg pressure

FBHP (Pwf)

Expected gradient

Design gradient

Operating Depth

Minimum mandrel spacing (Future)

Drawdown



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Design Exercise 1: Single Mandrel Gas Lift

Following well parameters are available:• Well depth 9000 ft. (2743.2 m) (Vertical) • FWHP: 250 psi (1723.6 kPa)

• Average flowing gradient above point of injection: 0.2 psi/ft (4.52 kPa/m)

• Gas lift available at well location: 1500 psi (10342.1 kPa), 120ºF (48.9 ºF)• Gas weight is 45 psi/1000 ft (1.02 kPa/m)

• ∆P required through the operating valve: 100 psi (689.4 kPa)

Locate the gas lift mandrel station depth if • The gradient can be reduced to 0.3 psi/ft (6.79 kPa/m) by pumping

Nitrogen through coiled tubing for well kick off, prior to placing on gas lift• The available gas lift system has to be used for unloading the well.

When shut-in, the fluid gradient in tubing may rise to 0.43 psi/ft (9.61 kPa/m)

Design Exercise 2A: Gas Lift IPO Unloading

Tubing size 4-1/2" (0.11 m)

Casing Size 9-5/8" (0.24 m), 47 lb/ft (70 kg/m)

Deviation Vertical well

Desired production 5000 BLPD (794.9 m3/day)

Watercut 50%

Desired TGLR 1000 scf/stb (178.1 m3/m3)

Oil gravity 35 °API

Water gravity 1.07

Gas gravity 0.65

Flowing wellhead pressure, temp 200 psig (1378.9 kPa), 140 °F (60 °C)

Gas lift kick off pressure 1400 psi (9652.6 kPa) at wellhead

Average reservoir pressure 3000 psi (20684.2 kPa)

Reservoir temperature 225 °F (107 °C)

Liquid PI 4 Bpd/psi drawdown (0.09 m3/ kPa)

Formation GOR 400 SCF/STB (71.2 m3/m3)

Mid perforation depth 8000 ft (2438.4 m)

Bottom mandrel depth (max depth) 7800 ft (2377.44 m)



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Design Exercise 2B: Gas Lift IPO Unloading

Tubing size 3-1/2" (0.09 m)

Casing size 9-5/8" (0.24 m), 47 lb/ft (70 kg/m)


Desired production 2000 BLPD (317.97 m3)

Watercut 50%



Water gravity 1.07

Gas gravity 0.65

Flowing wellhead pressure 200 psig (1378.9 kPa)

Surface temperature static / flowing 80 / 150 °F (27 / 66° C)


Avg reservoir pressure, temperature 3000 psi (20684.2 kPa), 216°F (102°C)

Liquid PI 2 Bpd/psi (0.05 m3/kPa) drawdown


Mid perf depth 7500 ft (2286 m)

Bottom mandrel depth 7200 ft (2194.56 m)

Completion fluid weight 8.6 ppg (1030.5 kg/m3)

Learning Objectives


Identify gas lift design methods



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Gas Lift Unloading Design Using IPO Valves: Worked Example

Example 2A

Recall - Gas Lift Design Steps

1. Collect data

2. Identify tubing sizing and mandrel spec (valve OD)

3. Design mandrel spacing

4. Position the operating valve

5. Position the unloading valves

6. Specify the unloading valve specs (port size and pressure setting)

7. Select the orifice valve port size

8. Validate the design



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Design Exercise 2A: Gas Lift IPO Unloading

Tubing size 4-1/2" (0.11 m) GLM with 1.5" pocket will be used

Casing Size 9-5/8" (0.24 m), 47 lb/ft


Desired production 5000 BLPD (794.9 m3/day)

Watercut 50%



Water gravity 1.07

Gas gravity 0.65

Flowing wellhead pressure, temp 200 psig (1378.9 kPa), 140 °F (60 °C)


Average reservoir pressure 3000 psi (20684.2 kPa)

Reservoir temperature 225 °F (107 °C)

Liquid PI 4 Bpd/psi drawdown (0.09 m3/kPa)


Mid perforation depth 8000 ft (2438.4 m)

Bottom mandrel depth (max depth) 7800 ft (2377.44 m)

2000

4000

6000

8000

200 400 600 800 1000 1200 1400 1600

Pressure, psi

Depth (TVD), ft

Mid Perforation Depth (8000 ft) [2438 m]

Bottom Mandrel Depth (7800 ft) [2377 m]

‐ Prepare a mm Graph sheet, taking Pressure along the horizontal axis and Depth along the vertical axis‐Mark the mid perf and bottom mandrel (max injection) depths

(kPa)(1379)

(2758) (4137) (5516) (6895)

(8274) (9653) (11 032)

(610)

(m)

(1219)

(1829)

(2438)



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Defining the Two Gradients

Expected Flowing Gradient

Generate the expected flowing gradient for the gas lifted well (after gas lift unloading):

• By modeling the GL well using a Nodal Analysis program• Using estimated flowing gradient (from similar wells), OR• Using published gradient curves

Plot the tubing pressure traverse vs. True vertical depth (TVD)

Expected GL gas gradient

Calculate the casing pressure profile starting with GL Kick off pressure (using equation or Chart)

Plot downhole casing pressure vs. True vertical depth (TVD)

2000

4000

6000

8000

200 400 600 800 1000 1200 1400 1600

Pressure, psi

Depth (TVD), ft


Bottom Mandrel Depth (7800 ft) [2377 m] 1372

1445 (Pwf) 1660

Expected flowing gradient

Expected GL Gas gradient (Kick off)

(kPa)(1379)

(2758) (4137) (5516) (6895)

(8274) (9653) (11 032)

(610)

(m)

(1219)

(1829)

(2438)



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Location of Top Mandrel

Unloading will begin by U-tubing, where the top of standing fluid level is found in the well (a function of reservoir pressure, THP and fluid gravity)

• Fluid column in the well: 3000 psi / 0.45 psi/ft = 6667 ft (2032 m)• Fluid level from surface = 8000 – 6667 = 1333 ft (if THP = 0 psig)

The worst case scenario is the well standing full up to surface

The mandrel spacing will be performed for the worst case scenario. The well will unload even if the reservoir pressure is higher

2000

4000

6000

8000

200 400 600 800 1000 1200 1400 1600

Pressure, psi

Depth (TVD), ft



1445 (Pwf) 1660

ΔP:60 psi2600 ft GLM-1 [792.5 m]

Unloading kill fluid gradient, 0.45 psi/ft(10.2 kPa/m)

Locate the top GLM by U‐tubing : draw the kill fluid gradient from the FWHP and determine the location of first GLM by allowing about 60 psi ΔP across the unloading valve (Pc >Pt)

(kPa)(1379)

(2758) (4137) (5516) (6895)

(8274) (9653) (11 032)

(610)

(m)

(1219)

(1829)

(2438)



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2000

4000

6000

8000

200 400 600 800 1000 1200 1400 1600

Pressure, psi

Depth (TVD), ft



1445 (Pwf) 1660

2600 ft GLM-1 [792.5 m]

4250 ft GLM-2 [1295.4 m]

Tubing Safety factor:Draw tubing design line by taking 10% safety factor at P1 (Ptbg design = FWHP + 0.1 * (Pcsg – Ptbg)

320 1370

Casing safety factor (1.5" OD IPO):Drop Pc by 30 psi for every mandrel (to close the upper valve)

Tubing Design Line

Pcsg available for second mandrel

(kPa)(1379)

(2758) (4137) (5516) (6895)

(8274) (9653) (11 032)

(610)

(m)

(1219)

(1829)

(2438)

2000

4000

6000

8000

200 400 600 800 1000 1200 1400 1600

Pressure, psi

Depth (TVD), ft



1445 (Pwf) 1660

2600 ft GLM-1 [792.5 m]

4250 ft GLM-2 [1295.4 m]

320 1370

Starting from the tubing design line at GLM‐1, draw the kill fluid gradient to determine the location of GLM‐2. Use the reduced casing pressure

ΔP

(kPa)(1379)

(2758) (4137) (5516) (6895)

(8274) (9653) (11 032)

(610)

(m)

(1219)

(1829)

(2438)



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2000

4000

6000

8000

200 400 600 800 1000 1200 1400 1600

Pressure, psi

Depth (TVD), ft



1445 (Pwf) 1660

2600 ft GLM-1 [792.5 m]

4250 ft GLM-2 [1295.4 m]

5450 ft GLM-3 [1661.2 m]

Using the same approach locate other deeper mandrels. Continue till the ΔP becomes less than 100 psi (689.5 kPa).

Starting from the tubing design line at GLM‐2, draw the kill fluid gradient to determine the location of GLM‐3. For every mandrel drop Pc by 30 psi (206.8)

(kPa)(1379)

(2758) (4137) (5516) (6895)

(8274) (9653) (11 032)

(610)

(m)

(1219)

(1829)

(2438)

2000

4000

6000

8000

200 400 600 800 1000 1200 1400 1600

Pressure, psi

Depth (TVD), ft


1372

1445 (Pwf) 1660

2600 ft GLM-1 (792.5 m)

4250 ft GLM-2 (1295.4 m)

5450 ft GLM-3 (1661.2 m)

6250 ft GLM-4 (1905 m)

6850 ft GLM-5 (2087.9 m)

7200 ft GLM-6 (2194.6 m)

7500 ft GLM-7 (Inactive) (2286 m)

7800 ft GLM-8 (Inactive) (2377.4 m)

Allow mandrels at bracket spacing (300 – 350 ft) [91‐107 m] at bottom as required

Mandrel Spacing Complete

(kPa)(1379)

(2758) (4137) (5516) (6895)

(8274) (9653) (11 032)

(610)

(m)

(1219)

(1829)

(2438)



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Mandrel Spacing Design Results

Eight gas lift mandrels required:• 5 Unloading valves (GLM-1 thru 5)• 1 Orifice valve (GLM-6)• 2 Dummy Valves (GLM 7-8)

Next Steps• Determine Valve port size for the IPO valve selected (based

on gas passage requirements during unloading)• Perform valve pressure setting calculations for each of the

unloading valve• Determine the Orifice port size

2000

4000

6000

8000

200 400 600 800 1000 1200 1400 1600

Pressure, psi

Depth (TVD), ft


1372

1445 (Pwf) 1660

2600 ft GLM-1

4250 ft GLM-2

5450 ft GLM-3

6250 ft GLM-4

6850 ft GLM-5

7200 ft GLM-6

7500 ft GLM-7 (Inactive)


Read tubing design pressures and casing pressures at each mandrel station depth

(kPa)(1379)

(2758) (4137) (5516) (6895)

(8274) (9653) (11 032)

(610)

(m)

(1219)

(1829)

(2438)

(792 m)

(1295 m)

(1661 m)

(1905 m)

(2088 m)

(2195 m)

(2286 m)

(2377 m)



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2000

4000

6000

8000

200 400 600 800

1000 1200 1400 1600

Pressure, psi

Depth (TVD), ft

Mid Perforation Depth (8000 ft) [2438 m] 1445 (Pwf)

2600 ft GLM-1

4250 ft GLM-2

5450 ft GLM-3

6250 ft GLM-4

6850 ft GLM-5

7200 ft GLM-6



100 140 180 220

225

Temperature, °F

Draw the static and flowing temperature gradients from mid‐perf to surface

Static

Flowing

Operating casing pressure

Gas Lift kick off pressure

(kPa)(1379)

(2758) (4137)

(5516) (6895) (8274) (9653) (11 032)

(610)

(m)

(1219)

(1829)

(2438)

(792 m)

(1295 m)

(1661 m)

(1905 m)

(2088 m)

(2195 m)(2286 m)(2377 m)

37.8 °C 37.8 °C 82.2 °C 104.4 °C

2000

4000

6000

8000

200 400 600 800 1000 1200 1400 1600

Pressure, psi

Depth (TVD), ft

Mid Perforation Depth (8000 ft) [2438 m] 1445 (Pwf)

2600 ft GLM-1

4250 ft GLM-2

5450 ft GLM-3

6250 ft GLM-4

6850 ft GLM-5

7200 ft GLM-6



100 140 180 220

225

Temperature, °F

Read the temperatures at mandrel depths (static for GLM‐1‐2 and flowing for deeper mandrels)

(kPa)(1379)

(2758) (4137)

(5516) (6895) (8274) (9653) (11 032)

(610)

(m)

(1219)

(1829)

(2438)

(792 m)

(1295 m)

(1661 m)

(1905 m)

(2088 m)

(2195 m)(2286 m)(2377 m)

37.8 °C 37.8 °C 82.2 °C 104.4 °C



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Unloading Valve Calculations

For GLM-1, select R-20, port size 0.25" (6.35 mm)

Calculate Pb• Pb = Pc (1-R) + Pt (R) = 1485 (0.93) + 675 (0.07) = 1432 psi (9873 kPa)

Calculate Pb@60°F (15.6°C)• Pb@60°F = Pb * Ct (Temperature Correction Factor)• Ct is 0.85 (from Temperature Correction Chart for a temperature of 140°F (60°C)

• Using static gradient at GLM-1 depth)

• Pb@60°F = 1214 psi (8370 kPa)

Calculate Test rack opening pressure (TRO)• Ptro = Pb@60°F / (1-R) = 1214/0.93 = 1300 psi (8963 kPa)

Repeat calculations for Mandrels 2-5

Notes: • Used static temperature gradient for the top two unloading valves

Valve Type Port Size (in.) R 1‐R

R‐20 0.25 (6.35 mm) 0.07 0.93

R‐20 0.31 (7.9 mm) 0.10 0.9

Orifice Valve Calculations

Perform orifice sizing calculations using tubing pressure and casing pressure at operating depth (GLM-6)

Using gas passage program (or spreadsheet / chart), determine by trial and error the size of the orifice valve that

• Will be able to inject set point lift gas rate[4.0 MMscf/Day (113 009 m3/day)], and

• Give a noticeable reduction in casing pressure when the well transfers to operating point

Results: • Orifice size: 0.5" (12.7 mm)

• Estimated casing pressure at surface after unloading: 1250 psi (8618 kPa)

Validate the design (QC) to ensure well will unload

Prepare the gas lift valve table to be sent to Gas Lift Shop



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Orifice Valve Sizing

(Note: See related graph on next slide)

(135 026.1 m3/Day)

(12.7 mm)

(10 307.66 kPa)

(9135.55 kPa)

(101.1°C)

7

3

Orifice Valve Sizing

(1379)(kPa)

(2758) (4137) (5516) (6895) (8274) (9653) (11 032)

(SCM/Day)

(28 317)

(56 634)

(84 951)

(113 267)

(141 584)

(169 901)

(198 218)

(226 535)

(254 852)



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Gas Lift Design Results (Example 2A)

GLM

No.

Mandrel

Depth, ft

(m)

Gas Lift

Valve

Type

(1.5" OD)

Gas Lift

Valve

Port Size

(mm)

Casing

pressure

at depth,

psig (kPa)

Tubing

design

pressure

at depth,

psig (kPa)

Temperature

used for

design, °F

(Ct)

Pb@T

Psig

Pb@T=

[Pc*(1‐

R)

+Pt*(R)]

Pb@60

Psig

Pb@60=

(Pb@T)*Ct

PTRO

Psig

Ptro =

(Pb@60F)/

(1‐R)

12600(792)

R‐201/4"(6.4)

1485(10 239)

675(4654)

140 (0.85) 1432 1221 1307

24250(1295)

R‐201/4"(6.4)

1510(10 411)

900(6205)

166

(0.81)1470 1196 1281

35450(1661)

R‐201/4"(6.4)

1515(10 446)

1060(7308)

198

(0.77)1485 1145 1226

46250(1905)

R‐201/4"(6.4)

1510(10 411)

1175(8101)

206

(0.76)1488 1132 1212

56850(2088)

R‐205/16"(7.9)

1505(10 377)

1250(8618)

213

(0.75)1479 1112 1240

67200(2195)

Orifice1/2"(7.9)

1480(10 204)

1310(9032)

214NA

‐ ‐

77500(2286)

Dummy‐

‐ ‐

87800(2377)

Dummy‐

‐ ‐

Gas Lift Design Complete

Gas Lift Operations and Diagnostics:Unloading Procedures, Gas Lift Efficiency,

Surveillance and Troubleshooting



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Learning Objectives



Unloading Guidelines

1. Hook up the tubing pressure, casing pressure and gas lift injection rates to chart recorders / trend display devices

2. Bleed tubing down into the oil manifold

3. Start injecting +/- 300 MCFPD (8,495.05 scm/day). Slowly increase injection so it takes 10 minutes for a 50 psig (344.7 kPa) increase in casing pressure. Continue until top valve passes gas

4. Slowly increase injection to allow casing pressure to build-up in 100 psig (689.4 kPa) increments every 10 minutes

5. Maintain injection rate about half of set point until the orifice is reached

6. Once the well is cleaned up and there is a notable drop in surface casing pressure indicating that the well has unloaded to the orifice, increase injection rate to set point



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0

1000

3000

4000

5000

6000

7000

2000

1000 2000

DE

PT

H F

TT

VD

1500500 2500 3000 3500

IPO Design: Valves Close With Drop In Casing Pressure

TUBING PRESSURECASING PRESSURE

DRAWDOWN

FBHP SIBHP

(304.8 m)

(609.6 m)

(914.4 m)

(1219.2 m)

(1524 m)

(1828.8 m)

(2133.6 m)

(3447 kPa) (6895 kPa) (10 342 kPa)(13 789.5 kPa)(17 236.9 kPa)(20 684.3 kPa)(24 131.7 kPa)

Gas Lift Response Curve

Economic limit of gas injected is often ½ of that needed for max oil rate

Gas Lift Rate: QG (Mscf/Day) (SCM/Day)

Tota

l Liq

uid

Rat

e (s

tb/lp

d)

(SC

M/D

ay)

IPR Base

(190.8)

(159)

(127.2)

(95.4)

(63.6)

(31.8)

(5663) (11 327) (16 990) (22 653) (28 317) (33 980)(39 643)(45 307)(50 970)(56 634)(62 297)(67 960)



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Improving Lift Efficiency

Gas Injection Rate (MMSCFD) (SCM/Day)

Pro

duct

ion

Rat

e (b

bls/

d (S

CM

/Day

)

0.5 1.001.5 2.0

3000

2500

2000

1500

1000

500

0

3500

2.5

Shallow injection depth

Deep injection depth

(556.5)

(477)

(397.5)

(318)

(238.5)

(159)

(79.5)

(14 158) (28 317) (42 475) (56 634) (70 792)

Gas Lift Efficiency Checklist

Single point lifting

Deeper lift (high gas lift pressure, OR using the available lift gas pressure)

Low tubing head pressure (reduced back pressure)

Optimum gas lift injection rate

Optimum sized tubing and surface flowline

Clean tubing and surface piping

Corrosion / Scale monitoring

Surveillance / Optimization systems in place



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When gas-lifted producers are losing fluid production, identify if the problem is:

• Inflow related• Outflow related

• Other data (e.g., flowline temperature)• Gas lift injection rate

• Casing (Gas Lift injection) pressure

• Flowing Tubing pressure

Troubleshooting: Surface Tools

Strip charts (electronic) continuous display

Production Well Tests

CO2 Tracer

Echometer

• Other data (manifold pressure, flowline temperature, etc.)

Troubleshooting: Downhole Tools

Flowing bottom-hole pressure and temperature surveys• To optimize gas lift• To gather periodic data

Flowing pressure / temperature gradient surveys • Identify lift problems in the string• Optimize gas lift in the well• Update / Calibrate well flow model

Production Logging / Temperature logging• Identify plugged up / non-contributing perfs• Water production profile of the producing zone

Pressure build up surveys• Evaluate skin data• Estimate average reservoir pressure

FGS Survey:

Extremely valuable!



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Flowing Gradient Surveys Performed with Wireline

Surface Equipment

1. Wireline Stuffing Box

2. Upper Section

3. Quick Union

4. Rope Blocks

5. Telescopic Gin Pole

6. Middle Section

7. Lower Section

8. Bleed-off Valve

9. Wireline Valve

10. Wireline Pulley

11. Wellhead Connection

12. Weight Indicator

13. Load Binder and Chains

14. Wellhead Adapter

Reservoir Details Formation – Black Gold

Layer pressure 2850 psia (19650.05 kPa)

Productivity Index- ( PI) - 3.5 STB/psi dd (0.08 m3/kPa)

P- GOR – 450 SCF/STB (80.1 m3/m3)

Production Total fluid – 4935 STBLPD (784.6 m3/day)

Oil – 296 STBOPD (47.06 m3/day)

BS&W – 94%.

Pressures Kick off pressure- 1450 psia (9997.3 kPa)

Operating casing pressure- 1200 psia (8273.7 kPa)

Tubing pressure – 195 psia (1344.4 kPa)

Completion 5 ½" (0.14 m) Tubing

9 5/8" (0.24 m) Production casing

Vertical Producer

Gas Lift Design Total Mandrel – 11

Unloading valves – R-25 P1 PPO valves

Lifting Point – GLM -11, RCC- 5/8" (0.02 m)

Example – Well-08A

Flowing Gradient Survey carried out to ascertain the gas lift performance



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Three Pen Chart at Surface

Well 08A

Green – Lift gas injection rate

Blue – Casing pressure

Red – tubing pressure

FGS Showing Healthy Gas Lift Performance

Gas Lift Design for Well 08ACorr: B &B (S); Lf=0.74; P bar=2850 psia; Pwf=1162 psia; PI=3.48:

Casing Gradient

Temperature Gradient

[685.8]

[1371.6]

[2057.4]

[2743.2] [kPa] [11 032] [13 790] [16 547]

Tubing Gradient

Opening pressures of PPO unloading valves

[49°C]

4500

6750

9000

[m]

40 80 160 200 240[4°C] [27°C] [71°C] [116°C][93°C]

120

400 800 1200 [8274]

[2758] [5516]1600 2000 2400

Temperature (degrees F)

(* see next slide forClose up of chart)



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FGS Showing Healthy Gas Lift Performance

Gas Lift Design for Well 08ACorr: B &B (S); Lf=0.74; P bar=2850 psia; Pwf=1162 psia; PI=3.48:

Casing Gradient

Temperature Gradient

(685.8 m)

(1371.6 m)

(2057.4 m)

(2743.2 m)[kPa][2758] [5516]

[8274]

[11 032] [13 790] [16 547]

Tubing Gradient

Opening pressures of PPO unloading valves

(4°C) (27°C)

(49°C)

(71°C) (93°C) (116°C)

FGS Helps Identify Gas Lift Inefficiency in Wells

Expected pressure gradient

Gas Injection Pressure

Measured pressure gradient

Expected temperature gradient

Measured temperature gradient

[38°C] [60°C] [82°C] [104°C] [127°C] [149°C]

(762 m)

(1524 m)

(2286 m)

(3048 m)(4137 kPa) (8274 kPa) (12 411 kPa) (16 547 kPa) (20 684 kPa)



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CO2 Tracer Survey

• Detect operating lift depth• Detect multiple points of injection / tubing leaks

WellTracer allows to quickly determine lift gas entry points in the well without running downhole tools

WellTracer creates a snapshot of the well performance by introducing a small volume of CO2 into the injection line then measuring CO2 concentration flowing back at the well head

The method has some limitations

CO2 Tracer Survey Set-up Schematic



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CO2 Tracer Survey Results

Survey showing single lift point

Survey showing multiple lift points

SPE 133268

Learning Objectives





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Gas Lift Well Unloading

Gas Lift Design using single gas lift mandrel

Gas Lift Design using multiple mandrels• Design with IPO Unloading valves• Design with PPO Unloading valves

GL Design Example well• Mandrel spacing• Valve selection• Pressure setting design• Orifice sizing

Surveillance and Trouble shooting• Maintaining Efficiency• Surface tools• Sub-surface tools

Session Summary

GL Well Unloading

GL Design with IPO valve string

Trouble shooting with Flowing

Gradient Surveys



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Documents

Gas Lift Fundamentalscloud1.activelearner.com/contentcloud/portals/hosted3/PetroAcademy/... · To Separator/Stock Tank INJECTION GAS ... Plot objective design gradient or trigger