Multiphase Pipeline Transport - · PDF fileMEK 4450 – Multiphase pipeline transport (IFE) ... Slug catcher, pre-separator 15: ... • Horizontal,

MEK 4450 – Multiphase pipeline transport (IFE)

Lecture notes 2013-10-22, Morten Langsholt

• Multiphase technology – What, why, how • Pipe flow – single and multiphase flow • Importance of relevant experimental data • From lab to field scale • Multiphase test facilities • Lab-demo with measurements

MEK 4450 Multiphase Flow - IFE Oct. 22, 2012

Multiphase pipe flow – a key technology for oil and gas production


What’s multiphase transportation? • Transport of gas, oil, water, chemicals and

possibly solid particles in the same pipe • Reduces need for new production platforms • Gather production from many wells and send

to existing platform or shore • Subsea separation and pumping/compression

may be required • More cost efficient • Often requires chemicals to prevent corrosion

and solids precipitation that can possibly restrict or stop the flow


Multiphase transportation challenges

• Capacity problems due to viscous oils, emulsions etc.

• Solids precipitation can restrict or stop the flow

• Liquid accumulation during low flow rates in gas condensate pipelines • Large flow transients during production ramp-up

• Slugging and other instabilities can give problems in the receiving facilities

• Erosion/corrosion


Application of multiphase flow models

• Tool for system design • Piping and equipment dimensioning • Heating and thermal insulation • Chemical choice and dosage

• Part of system simulator • Integrated system design • Subsea solutions • Operator training • Operation support – system overview • Surveillance: Compute non-monitorable parameters

- Liquid content, leak detection …


Pipe Flow – Some considerations related to single

and multiphase flow


Calculation of flow in pipes

in

out

• Conservation of • Energy • Mass • Momentum

• Thermodynamics


Mass conservation • Single-phase : Mass in - mass out = accumulated mass • Multiphase: Mass transfer comes in addition, e.g. for condensate: Mass in - mass out + local condensation = accumulated mass • Steady state single-phase flow: G = density *pipe area*mean velocity = ρAU=constant along a pipeline

• Gas: Pressure reduced with 50% implies a doubling of U • Oil: Small density variations => U constant along pipeline

in

out


Momentum balance – single-phase:

PL

PR

)(sin)( θgmAPP RL =−

L

Friction−

Friction

• Pressure gradient large enough for flow: Velocity depends on friction

• Friction = Friction force per area * wall area

LDUFriction w πτ ∗= ...),(

θ

Veggskjærspenning MEK 4450 Multiphase Flow - IFE Oct. 22, 2012

Multiphase Pipe Flow Depends on:

Fluid properties Pipe geometry Environment

Density Diameter T, external Viscosity Wall roughness Insulation (buried?) Phase fractions Pipeline profile/ T at inlet Conductivity topography P at inlet Heat capacity P at outlet Surface tension Etc... Varies with P and T ! P=pressure, T=temperature


Oil samples - large differences in

fluid properties

Crude oils • Njord • Visund • Grane • Statfjord C

Condensates • Sleipner • Midgard


Midgard

Multiphase flow Three-phase flow (here): Simultaneous flow of oil-gas-water in the same pipeline Flow regimes: Describes (intuitively) how the phases are distributed in the pipe cross section and along the pipeline Superficial velocity:

The velocity a phase will have if it were the only fluid present


Flow regimes steeply inclined pipes

Bubbly flow: Little gas, large Uoil (All inclinations)

”Churn”-flow: More gas, large Uoil (steep inclinations)

Annular flow: High Ugas, low Uoil (wide range of incl.)


Stratified/wavy- near horizontal pipeline

Large waves: More effective liquid transport

Stratified flow. Ugas normally >> Uoil


Hydrodynamic slugging

• Large waves that eventually block the pipe cross section pressure build up

• Intermittent flow – liquid slugs divided by gas pockets

• Effective liquid transport • Void in slug: Volume fraction of

entrained gas bubbles in the slug

Liquid slu

Taylor-bubble

Slug front in three-phase flow


Need for experimental data

• MP-flows are complex due to the simultaneous presence of different phases and, usually, different compounds in the same stream.

• The combination of empirical observations and numerical modelling has proved to enhance the understanding of multiphase flow

• Models to represent flows in pipes were traditionally based on empirical correlations for holdup and pressure gradient. This implied problems with extrapolation outside the range of the data

• Today, simulators are based on the multi-fluid models, where averaged and separate continuity and momentum eq. are established for the individual phases

• For these models, closure relations are required for e.g. interface and pipe-wall friction, dispersion mechanisms, turbulence, slug propagation velocities and many more

• These can only be established with access to detailed, multi-D, data from relevant and well-controlled flows


Up-scaling from lab to field

• 13 parameters determine holdup(s) and pressure drop in three phase pipe flow

• To develop the closure relations, we need data • To cover the parameter space we need, say,

513 ~ 109 data points for 5 point resolution in each parameter

• We have ~ 200 field data points at present

• It is clearly impossible to cover the parameter space of three phase pipe flow with data


Conclusion: we need models based on physics to

extrapolate beyond lab data

Lab Field


Dimensionless numbers – dynamic similarity

• Reynolds number, ratio of the inertial forces to the viscous forces,

Re= =ρvL/µ

• Froude number, ratio of a body's inertia to gravitational forces or ratio of a characteristic velocity to a gravitational wave velocity

• Weber number, relative importance of the fluid's inertia compared to its surface tensions:

Laminar vs turbulent flow Wave propagation, outlet effects, obstructions Formation of droplets and bubbles.


P = 100 bar 1 m/s

Corresponds to 10 m/s

Conditions in pipeline

1 m/s ρ = 1 kg/m3

Hydrodynamic forces proportional to rU2


Wind = 3 m/s Light breeze

Gas – liquid interaction: governed by Dρ*DU2

P = 100 bar

ρ = 600 kg/s

Ug = 3 m/s

Corresponds to more than 30 m/s, i.e. Full Storm

Typical gas-condensate pipe: Gas velocity of 6 – 7 m/s, corresponding to twice Hurricane force winds

Conditions in pipeline


Conditions in pipeline – Drops and bubbles

Liquid layer can be significantly aerated (40% - 70%)

Hydrocarbon systems can have very low surface tension, in particular gas-condensate systems. Encourages generation of smaller drops and bubbles. Typical values: Air – water: 0.07 N/m vs. Gas – condensate: < 0.005 N/m

P = 100 bar

3 – 6 m/s

3 – 6 m/s σρ

σρ

2

2

tensionSurfacenalGravitatio

tensionSurfaceInertial

dgEo

dUWe

==

==

Drop/bubble sizes Capillary waves

60 mm/h

90 000 mm/h measured in lab


Test facilities for study of multiphase flow behaviour


Open and closed loops Open loops with air as the gas phase – atmospheric pressure

• Simple to build, relatively low cost • Few safety barriers • Liquid phase e.g. water, vegetable oil • Common at Universities

Closed, pressurised flow loops • More complex design, higher costs • More realistic gas-liquid density ratio • Crude oils possible (unstable, EX) • Safety barriers against pressure burst

and explosion


Design considerations Main goal for a test loop: • Establish well controlled and relevant multiphase flows Common requirements: • Length/diameter ratio , L>300 D – flow develops along the pipe • Large diameter – diameter scaling difficult • Easily changeable pipe inclination • High gas density to give relevant gas-liquid density ratio • Large span in flow rates

Cost-benefit:

• Pressure vs gas density; pressure drives costs • Flow velocities vs pipe diameter; Flow rates drives costs – pumps and

separator • High L/D and pipe inclination drives cost of building


Some test facilities in Norway • IFE Well Flow Loop

• + All inclinations • + Indoor • + High gas density • + Transparent pipes • + Cost effective

• SINTEF – Large Sc. • + Long L/D • + Large diameter • + High pressure, N2

• Statoil - Herøya • + Real oil-gas system • + Formation water • + High pressure • + Long, high L/D

• - Short, low L/D • +/- Medium diam.

• - Fixed inclination • - Expensive to run • - Outdoor

• - Cumbersome to change inclination

• - Small diameter • - Steel pipe • – Expensive to run • - Outdoor



The Well Flow Loop – Principal Layout Component list: 1: Oil-water separator 2: Gas-liquid separator 3: Gas compressor 4: Water pump 5: Oil pump 6: Heat exchanger, gas 7: Heat exchanger, water 8: Heat exchanger, oil 9: Main el. board 10: Flow rate meter, gas

11. Flow rate meter, water 12: Flow rate meter, oil 13: Inlet mixing section 14: Slug catcher, pre-separator 15: Return pipe, gas 16: Return pipe, liquid 17: Test section

18: Winch

Worldwide test loops


Worldwide test loops


Instrumentation (to be covered next week)

• Gamma densitometers • PIV • X-Ray tomography • LDA/PDA • ECT


Pressure gradients • Differential pressure transducers;

many measurement principles, accuracy, response times etc.

• Connected to an upstream and downstream pressure tap (small holes in the wall)

• The connecting pipe is called impulse pipe.

• Pressure tap can be top/bottom/side mounted

• Distance between pressure taps can vary widely (1 m – 100 m)

• Measures wall friction and the hydrostatic pressure difference between the taps

• dp/dz [Pa/m]= dp/dL, where dp is the differential pressure measured with the transducer and dL is the distance between the tappings


Holdup=Cross-sectional liquid fraction (H=1-α) • Gamma densitometer • Attenuation of photon flux due

to absorption and scattering

• Single media: where N is the intensity, µ is the attenuation coefficient (material property) and x is the distance travelled in the media

• Two-phase gas-liquid

• This can be developed to and explicit equation for the Holdup


Lab demo and practical work

• Where is what and why – get to know the loop • The control and data acquisition system • Demonstration • Exercise for next week


Tentative lab-demo - Flow regimes

• Downwards -1o, Usl=0.30 m/s, Usg=1 m/s Strat. w/smooth interface • Horizontal, Uso=0.30 m/s, Usg=1.5 m/s Strat. w/large waves • Horizontal, Uso=0.30 m/s, Usg=3 m/s Strat w/ripple waves • Horizontal, Uso=0.30 m/s, Usg=4-8 m/s Trans. From strat. annul. • Upward 1o, Uso=0.40 m/s, Usg=0.3 m/s Elongated bubbles • Upward 4o, Uso=0.12 m/s, Usg=0.9 m/s Slug flow • Upward 4o, Uso=0.12 m/s, Usg=3 m/s Large waves/short slug • Upward 4o, Uso=0.12 m/s, Usg=5 m/s Strat. w/drops and void in liq. • Horizontal, Uso=Usw=0.1 m/s, Usg=1 m/s Stratified gas-oil-wat. • Horizontal, Uso=Usw=0.1 m/s, Usg=3 m/s Strat. mix o/w-gas


Lab data T e st co nd itio ns Fluid p ro p e rtie sPressure 4 bara Density Dyn. vis Kin.vis

Pipe dia. 0.099 [m] [kg/m3] [Pa s] [m2/s]

Pipe area 0.0077 [m2] Oil 815 0.002 2.44E-06

Pipe rough 0.00025 [-] Gas 24 0.000015 3.01E-07

Exp no Incl. Usgas Usoil dp/dz Holdup Flow regim# θ [m/s] [m/s] [Pa/m] [-]


Stratified flow model in spreadsheet (Excel)

β


T e st co nd itio ns Fluid p ro p e rtie s Ge o me try Re sults

Pressure 4 bara Density Dyn. vis Kin.vis Pipedia 0.099 m

Pipe incl. 4 [Deg.] [kg/m3] [kg/s m] [m2/s] PipeArea 0.00770 m Holdup 0.2 [-]Sup. Gas vel. 3.5 [m/s] Oil 815 0.002 2.45E-06 Rel. Pipe rough 0.00020202 - dp/dz 230.7 [Pa/m]

Sup. Liq. Vel. 0.3 [m/s] Gas 23 0.000015 6.52E-07 Abs. Pipe rough 0.00002 m Tuning 1

β δl/π -(ρ l-ρg)gsin(θ) −τwlSl/Al τwgSg/Ag τiSi/Ag*β F(β) [SiρgUg2/ρ lgAg]0.5 [Siρ lUl

2/ρ lgAl]0.5 τwg τwl τi Al Ag

Holdup WetAng,dl Gravity WallSh,liq WallSh,g Int.Shear Grav.dom. Fr,gas Fr,liq Area,L Area,G

0 [-] [N/m 3] [N/m 3] [N/m 3] [N/m 3] [-] [-] [m2] [m2]

Exercise for next week

1. Open the Excel-file and get familiar with how to use it 2. Use data from the lab test and ‘plug’ the data into the model. Compare

the predicted holdup and pressure drop values with the measured data for the different test conditions. Discuss the results.

3. For pipe inclination 3 deg. and Usl=0.5 m/s, calculate and plot the pressure drop as a function of the gas velocity. Explain the results.

4. Describe what occurs for pipe inclination 4 deg, Usl=0.001 m/s and Usg= 3.5 m/s.

β


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Multiphase Pipeline Transport - · PDF fileMEK 4450 – Multiphase pipeline transport (IFE) ... Slug catcher, pre-separator 15: ... • Horizontal,