1 intro to mf hydraulics upd

7/30/2019 1 Intro to MF Hydraulics Upd

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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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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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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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