W4- O&G Multiphase Flow & Assurance Flashcards
Flow assurance
How fluids interact in different operations
Reservoir types
NG, gas condensate, crude oil, heavy crude
Fluid characterisation
Governs material and equipment specs, affecting P drop, heat transfer, pipe corrosion, deposits
Thermodynamic properties
Bubble point
Dew point
2 phase region
Cricondenbar: max pressure above no gas will form
Cricondentherm: max temp above which no liquid will form
Critical point: liquid and gas phase properties equal
Fluid flow & effects of gravity
Gravity affect flow of liquids more than gases
Inclination affects multiphase flow
Gravity alters local liquid hold-up (from velocity changes)
Liquid accumulation occurs at low pipeline points due to gravity and inclination
Liquid velocity decreases in upward flow, but downward flow causes liquid acceleration
Gravitational effects less critical at high velocities due to inertia
Liquid hold-up
Ratio of liquid to total volume
Gas hold-up
Ratio of gas to total volume
What will be the liquid hold up for equal flow rates of liquid/gas
HL > 50% as gas will slip through due to greater velocity (lower viscosity, no internal friction
Pipeline angle effect on liquid hold up
Upward flow have higher liquid hold-up as gravity slows liquid down and densities differ vastly
Superficial velocity
velocity of fluid if occupied by full cross sectional area:
U= Q/A
HG + HL = 1
No-slip (homogeneous) assumption
Gas and liquid travel at same velocity (faster gas phase doesn’t slip past liquid)
No-slip hold up: Q/Qtot
Vertical flow regimes
Increase gas flow:
Bubbly: distribution of bubbles throughout liquid
Slug: gas flow rate increased where bubbles coalesce to form slugs
Churn: churning of irregularly shaped portions of gas & liquid
Annular: liquid flowing at wall and gas in core, with liquid droplets (entrained droplets do not coalesce)
Horizontal flow regimes
Increase gas flow:
Bubbly: bubbles confined at top of pipe, liquid below
Plug: bubbles coalesce to form larger bubbles
Stratified: gas plugs join to form a continuous gas layer on top
Wavy: waves on surface of liquid from interfacial shear stress
Slug: waves grow until crest at top pf pipe and gas breaks through, with liquid distributed over wall
Annular: liquid flowing at wall and gas in core, with liquid droplets (entrained droplets do not coalesce)
Spray/mist: majority of liquid dispersed as droplets in gas core, liquid film very thin
Horzonal flow effects of pressure, inclanation, viscocity
Pressure: increased pressure, less slug formations
Upward inclanation- slug formation amplified as gas flow easily up liquid
High viscosity- slug formation area amplified
Vertical flow regime effect of pressure
Increased pressure, less slug formation area
Total pressure drop over a pipeline
Delta PT = Delta Pf + Pel + Pacc
Single phase Delta Pf = f(L/d)[(p*mu^2)/2]
What force dominates for different flow rates at high pressure losses?
Low flow: Gravity dominated
High flow: friction dominated
Elevation pressure loss, Delta Pel
Delta Pel = psgL*sin(a)
For slip: ps = pLHL + pGHG
L = segment length
a = segment angle v horiztonal
Acceleration pressure loss, Delta Pacc
Pacc = (1/pL){(m/A)^2]{[(1-xe)^2/(1-a)] +[(xe^2pL)/(aPg)]}
Frictional pressure loss, Delta Pf (no slip)
Delta Pf = fms(L/d)[(Pns*Vm^2)/2]
pms = /\LpL + /\GpG
Frictional pressure loss due to fittings
Delta Pf = K[(pV*m^2)/2]
Frictional pressure loss, Delta Pf (slip)
Delta Pf = ftp(L/d)[(pns*Vm^2)/2]
ftp = mtp*fns
Multiphase flow models/correlations categories
1) No slip + no flow regime considered (LM & Homogeneous flow model)
2) Slip + no flow regime considered (two phase friction factor and H-B liquid hold-up correlation)
3) Slip + flow regime considered (computational)
Slugging and types of slugging
Unstable multiphase flow of intermittent L+G surges
Hydrodynamic & terrain-induced
Hydrodynamic slugging
Induced from flow regime
L+G interactions induce instabilities (liquid waves) spreading to entire pupe by merging and growth
Terrain-induced slugging
Formed from inclination (hold-up changes) and elevation pressure drop.
Liquid waves form slugs and merge.
At low points, liquid hold up increases so area for gas to flow decreases meaning instability to liquid
Sever riser slugging
Special case of terrain-induced slugging at low points of inclined and vertical riser section.
1) Riser fills with liquid as gas pressure too low to overcome liquid hydrostatic pressure developing
2) Slug growth and gradually blocks riser- obstacle causing upstream gas pressure build up until riser full and begins to empty
3) Riser backpressure (due to gas) increases due to blockage and empties - gas pushes liquid out riser more rapidly as hydrostatic head decreases
4) Force balance shift causes large liquid slugs up riser volume, then large gas surges. Gas blowdown
Pipeline operation slugling
Transition phenomena in operations- during flow or pressure changes (start-up/shut down) liquid hold up changes and creates slugs
Pigging
Where pig removes wall deposits against corrosion and pressure drop
Interference with waves causes slugs
Slugging mitigation
Early routine decisions
Line minimisation
Riser base life gas injection
Control systems
Slug catchers
Downstream of pipelines to absorb impact of large liquid surges associated with slugging
Large volume to allow sufficient residence time to settle and withstand large hydraulic forces (thick walls & long, parallel pipes)
Pipeline insulation methods
Pipe in pipe (PIP) insulation: insulation in outer pipe
Multilayer insulation: layers of different materials
Bundle flowline insulation: several fluid pipes in a larger pipe
Pipeline burial: partial/full burial in seabed
What can reduce insulation of pipes?
Deep-water hydrostatic pressure allows water to seep into it, reducing effectiveness
Heat losses between reservoir/pipeline/facility temps
Weak points- manifolds, joints, valves
Riser heat losses
Manifold heat losses
Pipeline heat losses
Active heating and stabilisation of pipeline temp methods
Indirect heating of the pipeline
Inductive heating:
Direct electrical heating:
