Post on 13-Jul-2018
Virtual Session 1
Gas Lift Fundamentals
Gas Lift Principles: Definition, Advantages, Completions
Gas Lift Fundamentals ═══════════════════════════════════════════════════════════════════════════════════
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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
Conventional Mandrel with Gas Lift Valve
Conventional Mandrel with Gas Lift 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 Pocket Mandrel with Gas Lift Valve
Side Pocket Mandrel with Gas Lift Valve
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
Side Pocket Mandrel with Gas Lift Valve
Side Pocket Mandrel with Gas Lift Valve
Side Pocket Mandrel with Gas Lift Valve
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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
Side Pocket Mandrel with Gas Lift Valve
Side Pocket Mandrel with Gas Lift Valve
Side Pocket Mandrel with Gas Lift Valve
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)
Static Pressure Gradient Exercise
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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Static Pressure Gradient Exercise
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
Gas Lift Fundamentals ═══════════════════════════════════════════════════════════════════════════════════
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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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