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INTRODUCTION TO
MULTIPHASE FLOW HYDRAULICS
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MULTIPHASE PRODUCTION
The simultaneoustransfer ofhydrocarbon liquid,gas and water fromreservoir via wells andpipes to the finalseparation unit.
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Phase envelopes: Gas Condensate and Oil
0
100
200
300
400
500
600
-200 0 200 400 600 800T (C)
P(BAR
A)
Oil Dew Points
Oil Bubble Points
Oil Critical Point
GC Dew Points
GC Bubble Points
GC Critical Point
GAS
Condensate GAS
OIL
Gas and
Liquid
Gas andLiquid
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Application Examples
On-shore oil gathering system
(Saudi Arabia)
Gas-condensate
production and transfer to
shore (North Sea)
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Multiphase Production - Total System
The total producing system includes the reservoir
the wells, flow-lines/pipelines and
the receiving facilities
Each element affects the others.
Efficient operations requires mutualcompatibility.
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Pr
drainage
boundary
well bore
Pwf
Pwh
P riser
base
wellhead
riser
base
P sep
flow line
separator
Example:
pressure losses in a
well-flowline -riser
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Multiphase ? Gas + Droplets
Liquid Hydrocarbons Gas bubbles
Water droplets
Free Water
Oil droplets Gas bubbles
Hydrates
Wax Sand
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Multiphase flow predictions
are difficult because of:
several flow regimes phase velocity
differences
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Typical flow regimes (Horizontal flow)
Stratified flow
(Annular flow)
Dispersed bubble flow
Slug flow
SEPARATED
DISTRIBUTED
hydrodynamic slug flow
stratified flow
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Flow regimes (in OLGA)(Vertical flow)
Annular flow
Dispersed bubble flow
Slug flow
SEPARATED
DISTRIBUTED
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Important definition
Slip is the ratio of the gas velocity to the liquid velocity
average UGas
average
ULiq
Slip =
normally 1 for co-current horizontal or upwards flow
for downward co-current flow the value may be < 1
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Important definition
Liquid Holdup is the local liquid volume fraction Gas fraction is the local gas volume fraction
Gas Flow Area
(AG)
Liquid Flow Area
(AL)
Liquid holdup = AL/(AG + AL)
Liquid holdup + Gas fraction = 1
Pipe c ross sec t ion w i t h st ra t i f ied f low
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Important definition
Phase velocitiesSuperficial phase velocities(reduced phase velocities)
Q = local volume flow rateUG = QG/AGUL = QL/AL
AT = AG + ALUSG = QG/ATUSL = QL/AT
Mixture velocity
UM = USL + USG
Gas Flow Area
QG
Liquid Flow Area
QL
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axial length L1 = axial length L2
all other boundary parameters and fluid
properties are also equal
dP1/dP2 1
Single phase flowL1
L2
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dP1/dP2 = ?
Gas-Liquid flow
L1
L2
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General relation for pressure and flow
Assume pipe outlet pressure given andfixed
Flow rate
Inletpr
essure
Friction dominatedGravity dominated
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Pressure, total liquid content and flow rate
Flow rate
Inlet
pressure
Totalliqu
idconte
nt
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Multiphase Flow Production is Transient !
Well operations (shut-in, re-
start)
Slugging
Rate changes
Pigging Blow-down
Tube ruptures and leakage
Valve failures Tripping of pumps and
compressors
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Terrain slugging
The terrain slugging cycle: A: Flow at low points are
blocked by liquid
B: Pressure builds upbehind the blockage
C&D: When pressure
becomes high enough, gasblows liquid out of the lowpoint as a slug
A. Slug formation
B.Slug production
C. Gas penetration
D. Gas blow-down
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HYDRODYNAMICSLUGGING
Slug Length
F
requency
b . - s lu g d i s t ri b u t i o n
3
p i p e 2 p i p e 3p i p e 1
12
a .- te r r a in e ff e c t a n d s lu - s lu in t e ra c tio n
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Hydrodynamic slugging
Two-phase flow pattern maps indicatehydrodynamic slugging, but
slug length correlations are quite uncertain
tracking of individual slugs along the pipeline isnecessary to estimate the volume of the liquidsurges out of the pipelines
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Pigging
Pigging a line will create a liquid slug ahead of the pigwhich normally is followed by a gas bubble. Both are
a challenge to receiving facilities.
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Rate changes
Pipe line liquid content decreases withincreasing flow rate
Rate changes may trigger liquid instabilities
Gas Production Rate
LiquidInventory
Initialamount
Final
amount
Amount
removed
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Shut-in - Restart
Liquid redistributes due to gravity during shutin
On startup, slugging can occur as flow is ramped up
B-Gas and Liquid Outlet Flow
A-Liquid Distribution After Shutdown
Flow
rate
gas
liquid
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Some rules of thumb:
Pipeline with many dips and humps:
instabilities are likely at low flow rates (i.e. terrain
induced) stable flow is possible at high rates
Low Gas Oil Ratio (GOR):
increased tendency for unstable flow Gas-condensate lines (high GOR):
may exhibit very long period transients due to low
liquid velocities Low pressure
increased tendency for unstable flow
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Temperature and flow assurance
GasOil
Reservoir Temperature
> 70 C
Emulsion40oC/104oF
30oC/86oF
20o
C/68o
F
Wax
Hydrate
Water drop out
Hydrate
< 0oC/32oF(determined by ambient +
Joule Thomson)
< 0oC/32o F
(determined
by ambient)ambient < -50 C
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VISCOSITY and its models
IMPORTANT but not THAT IMPORTANT
NEWTONIAN Viscosity depends on temperature (and pressure)
BINGHAM
Fluid must overcome a yield stress to flow Viscosity does not reduce with increased velocity
POWER LAW
Viscosity reduces with increased velocity shearthinning
No yield stress
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Effective viscosity in mixtures
Effective viscosity vs. temperature
(Uliq.,mix = 3.5 m/s, WC=70% and GLR =53)
0
5
10
15
20
25
30
35
30 35 40 45 50 55 60
Temperature (C)
Visc
osity(CP)
Calculated visco sity ignoring emulsion effect
M easured effective viscosity
Advanced Well Modelling
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Advanced Well Modelling Production/Injection Wells
What can you investigate / simulate ?
Slugging
Production Start-up and shut down Production from several reservoir zones
(multilayers, multilateral wells) Analyse cross flow
Reservoir injection e.g. (WAG) Smart Wells Gas Lifting Liquid Loading / Water - Condensate
Well Testing Segreg/wellbore effects Blowout
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A simple well simulated with OLGA
-1600
-1200
-800
-400
0
-800 -400 0
m
m
example:
Pwh varied from 30 to
50 bara in steps of 5
bar
tube ID = 0.101
Pres = 125 bara
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Liquid flow
and Pbh
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With slugtracking:
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Well and flowline-riser
-2000
-1500-1000
-500
0
500
-1000 0 1000 2000 3000 4000 5000
Well
Flowline-Riser
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that gives this liquid flow on the topside:
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Entire system:
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Conclusion
Multiphase flow systems are strongly dependingon their boundary conditions
Be careful with:
separating the system - e.g. well-tubing fromflowline-riser
trusting steady state solutions in particularwhen the pressure losses are gravitydominated.
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