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Virtual Session 1

Gas Lift Fundamentals

Gas Lift Principles: Definition, Advantages, Completions

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

©PetroSkills, LLC. All Rights Reserved. _________________________________________________________________________________________________________

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Learning Objectives

This section will cover the following learning objectives:

Explain the role of gas lift in a well performance analysis process

Identify the advantages and disadvantages of gas lift as an artificial lift method

Natural Flow Well vs. Gas Lifted Well

NATURAL FLOW WELL GAS LIFTED WELL

Fluid column weight reduced by formation gas in a natural

flow well

Fluid column weight reduced by formation and injected

gas: a gas lift well

Lower flowing bottom hole

pressure

Higher magnitude of production

Lower back pressure of formation



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Impact of Gas Lift on Flowing Gradient

PRESSURE (PSI)

DE

PT

H (

FT

TV

D)

1000

2000

3000

4000

5000

6000

7000

01000 20000

FBHP

SIB

HP

CONTINUOUS FLOW GAS LIFT WELL

Tubing Production;

Annular Gas Lift Injection

CASING PRESSURE WHEN WELL IS BEING GAS LIFTED

OPERATING GAS LIFT VALVE

(6895 kPa) (13 790 kPa)

(305 m)

(610 m)

(914 m)

(1219 m)

(1524 m)

(1829 m)

(2133 m)

InjectionGas

ProducedFluid

Gas lift is a means of artificial lift involving the injection of high pressure gas downhole into the produced fluid column. The injected gas increases the gas-liquid ratio, reduces the fluid density and column weight of the produced fluids, creating a pressure differential between the wellbore and reservoir

Gas Lift Definition

• Aeration or lightening of fluid column (density reduction)• Gas expansion, assisting the fluid to move to surface



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CONDITION CONTINUOUS FLOW INTERMITTENT FLOW

Production Rate (bbl/day)

100–75,000 Up to 500

Static BHP (psi) > 0.3 psi/ft (6.79 kPa/m) < 0.3 psi/ft (6.79 kPa/m)

Flowing BHP (psi) > 0.08 psi/ft (1.81 kPa/m) 150 psi (1034.2 kPa) and higher

Injection Gas (scf/bbl) (m3/m3)

50–250 (8.9–44.5) per1000 ft (304.8 m) of lift

250–300 (44.5–53.4) per1000 ft (304.8 m) of lift

Injection Pressure (psi)

> 100 psi (689.47 kPa) per 1000 ft (304.8 m) of lift

< 100 psi (689.47 kPa) per 1000 ft (304.8 m) of lift

Gas Injection Rate Larger volumes Smaller volumes

Types of Gas Lift

Continuous flow gas lift

Intermittent gas lift

Continuous Flow Gas Lift

A steady flow of high pressure gas is injected into the production tubing to aerate and lighten the fluid column.

A series of gas lift valves are run to allow the deepestpossible lift point

Production rates can range from 200 BLPD (31.8 m3) through 2"(0.05 m) tubing up to 50,000 BLPD (7949.3 m3) in 7" (0.18 m) tubing



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Gas Lift Advantages

Proven method

Cost of downhole equipment low

Can be installed and serviced without workover

Flexible to changes in operating conditions

Unaffected by sand, scale and asphaltenes

Good for deviated wells

Allows downhole chemical injection

Good in hot wells

Can use compressors designed for other use

Tolerates high GOR

Open tubing for PLT

Gas Lift Disadvantages

Gas supply needed

More gas to handle

May be slow to start up after shutdown

Gas supply flowline needed to each well

Tubing, casing and wellhead design should withstand high pressure gas

Safety hazard

Hydrates

Drawdown less than ESPs

Valve interference; heading



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Gas Lift Costs

Provision of gas supply

Gas compression

Power provision

Gas piping to the wellhead

Gas lift completion (sometimes dual)

Gas lift string installation

High capex, low opex

Gas Lift Completions: Conventional Valves

Conventional valves require the tubing to be pulled to service the valves

Gas LiftConventional Injection Pressure‐Operated Valves

Time-Cycle Controllerand Motor Valve

Conventional Mandrel with Gas Lift Valve




Packer

Landing Nipple



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Wireline Retrievable Valves

Wireline retrievable require kickover tools to be run down the tubing to service the valves

Tubing does not have to be pulled

Tubing open to full flow

Used extensively offshore

Gas LiftWireline Retrievable Valves

Adjustable Choke

SubsurfaceSafety Valve

Packer

Landing Nipple

Side Pocket Mandrel with Gas Lift Valve

Sliding Sleeve



Side String for Injection

No pressure on casing

Easily controlled

More expensive to set up

Stable and not subject to surging and heading

Gas LiftRetrievable Valves Side Pipe Injection

Adjustable Choke

Gas Injection Conduit

Packer

Landing Nipple






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High Rate Annular Completions

Annular flow can be 30,000-60,000 bpd (4769.6–9539.2 m3) if annulus is big enough

Well integrity/safety issues

Gas LiftWireline Retrievable Valves ‐ Annular Flow

Adjustable Choke

Bull Plug




Dual Zone Completion

If two zones isolated and gas lift used, it can be hard to split injection gas as desired on a design basis

Gas LiftWireline Retrievable Valves – Dual Zone

Adjustable Choke

Subsurface Safety Valves

Packer

Landing Nipple

Side Pocket Mandrels with Gas Lift Valves

Dual Packer

Blast JointLanding Nipple



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Intermittent Gas Lift

Learning Objectives

This section has covered the following learning objectives:

Explain the role of gas lift in a well performance analysisprocess

Identify the advantages and disadvantages of gas lift as anartificial lift method



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Gradient Calculations: Single Phase, Multi-phase Flow

Learning Objectives

This section will cover the following learning objective:

Explain the principles of multi-phase flow and the principleof gas lift



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Pressure Gradient (1)

The pressure change per unit length is called the pressuregradient and is expressed as psi/ft

For incompressible single phase flow, for a constant flow rate, thepressure drop can be expressed as a constant pressure changeper unit length

However, within the flowing well, two phase vertical flow isencountered and hence a constant pressure gradient cannot beused as the pressure gradient changes with depth

Many equations are required to determine the two-phasepressure gradient and so a graphical representation in the form ofa pressure-depth traverse is the simplest

Pressure Gradient (2)

Pressure (psi)

= Fluid gradient (psi/ft) x Vertical fluid column length (ft)

Fluid gradient (psi/ft)

= Specific gravity x 0.433 psi/ft (2.99 kPa/m)

Fluid gradient (psi/ft)

= 0.052 x Density (lbs/gal)

Oil gradient (psi/ft)

141.50.433 /

131.5x psi ft

API



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Static Pressure Gradient Exercise

Static pressure measurementsare available from a vertical well shut-in for the last six months

Calculate:• The static BHP of the well• The water, oil and gas gradient• The water-oil interface and oil-

gas interface depths• Suggest a single point gas lift

depth if lift gas is available at1400 psia (9652.66 kPa)(gas gradient 45 psi/1000 ft)(1.02 kPa/m)

Depth, ftMeasured

pressure in psia

Xmas tree 0 225 (1551.3 kPa)

1000 (304.8 m) 251 (1730.5 kPa)

2000 (609.6 m) 602 (4150.6 kPa)

3000 (914.4 m) 976 (6729.2 kPa)

4000 (1219.2 m) 1349 (9301.02 kPa)

5000 (1524 m) 1725 (11893.4 kPa)

6000 (1828.8 m) 2148 (14809.9 kPa)

7000 (2133.6 m) 2600 (17926.3 kPa)

8000 (2438.4 m) 3048 (21015.2 kPa)Tail pipe (EOT) 8800 (2682.2 m) 3407 (23490.4 kPa)

Mid-perf 9100 (2773.6 m)


BHP at mid-perf depth = 3540 psi (24407.4 kPa) (extrapolated from8800 ft (2682.2 m) to 9100 ft (2773.6 m))

Static gradients:• Water = (3048-2148)/2000 = 0.45 psi/ft (10.18 kPa/m)

• Oil = (1725 – 976)/2000 = 0.375 psi/ft (8.48 kPa/m)

• Gas = (251-225)/1000 = 0.026 psi/ft (0.59 kPa/m) (should be muchless; data suspect)

Interface depths:• Water-oil: ~5500 ft (1676.4 m) (refer to graph)• Oil-gas: ~1000 ft (304.8 m) (refer to graph)

Single point gas lift depth: 4000 ft (1219.2 m) (refer to graph)

Solution



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0

1000

2000

3000

4000

5000

6000

7000

8000

9000

10000

0 500 1000 1500 2000 2500 3000 3500 4000

Pressure, psia (kPa)

Annulus Gas gradient

ΔP

Gas Oil Interface

Oil Water Interface

Solution

GL KO Pressure, psia

Measured pressure in psia

Wireline depth, ft

1400 (9652.6 kPa)

225 (1551.3 kPa) 0

1445 (9962.9 kPa)

251 (1730.5 kPa)

1000 (304.8 m)

1490 (10273.1

kPa)

602 (4150.6 kPa)

2000 (609.6 m)

1535 (10583.4

kPa)

976 (6729.2 kPa)

3000 (914.4 m)

1580 (10893.7

kPa)

1349 (9301.02

kPa)4000

(1219.2 m)1625

(11203.9 kPa)

1725 (11893.4

kPa)5000

(1524 m)1670

(11514.2 kPa)

2148 (14809.9

kPa)6000

(1828.8 m)1715

(11824.5 kPa)

2600 (17926.3

kPa)7000

(2133.6 m)1760

(12134.7 kPa)

3048 (21015.2

kPa)8000

(2438.4 m)1796

(12382.9 kPa)

3407 (23490.4

kPa)8800

(2682.2 m)

Learning Objectives

This section has covered the following learning objective:

Explain the principles of multi-phase flow and the principleof gas lift



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Nodal Analysis:Finding the Possible Production Rates

Learning Objectives

This section will cover the following learning objective:

Estimate the production rate achievable by the gas lift



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Nodal Analysis

Estimate the inflow performance

Perform pressure drop calculation for a number of different flowrates = generate family of pressure traverse curves

Calculate VLP = wellbore flowing pressures for different flowrates against a constant WHP

Solve simultaneous equations defined by VLP and IPR, givingunique solution at selected “solution” node

The intersection of the VLP and IPR curves denotes the“operating” point of the system

Operating Point

Operatingpoint =stable

equilibrium

For a given flowrate, drawdown yields BHFP much greater than required by tubing to lift against WHP: too much energy

For a given flowrate, drawdown yields BHFP much less than required by tubing to lift against WHP: not enough energy

(17236.8 kPa)

(13789.5 kPa)

(10342.1 kPa)

(6894.7 kPa)

(3447.3 kPa)

(11.92 m3/Day) (23.85 m3/Day) (35.77 m3/Day) (47.70 m3/Day)



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Reservoir fluid PVT Summary Curves

Reservoir fluid PVT property curves vs. pressure

Learning Objectives

This section has covered the following learning objective:

Estimate the production rate achievable by the gas lift



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Nodal Analysis Modeling of GL Well

Gas Lift: How does it work

Costs and challenges associated with setting upgas lift operations

Static vs. flowing gradient

Multi-phase flow and stability

Flowing Gradient plots

Gas Lift well modeling• Gas Lift initiation & operating point• Gas Lift sensitivities:

– Tubing size

– GL Injection depth (Lift gas pressure)

– GL Injection rate– Flowing wellhead pressure

– Water-cut

Session Summary

Requirements for gas lift well

Multiphase flowing gradient

Gas Lift modeling & Sensitivities



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