Page 42 - Handbook Of Multiphase Flow Assurance

2. Initial diagnosis and solution of flow assurance production problems in operations 37

electrons from the production system wall material and dissolves it. Iron sulfide (black
powder) can be pyrophoric when exposed to air.
Diamondoids deposition (adamantane, diamantane, triamantane)—looks as a white
solid. Diamondoid deposits commonly occur in gas and gas condensate pipelines.
Emulsions are fluid but can be very viscous if stabilized by solids. Stability is caused by
asphaltenes, chemical inhibitors, mineral fines or waxes. Emulsions commonly occur
from wellbore to surface or topsides process equipment, but can also be present in
reservoir.
Erosion of pipes, pipe elbows or valves—caused by droplets and solids. Typically occurs at
locations where flow changes direction. Erosion corrosion can occur where a fluid flow at
high velocity strips away the protective film of corrosion product or inhibitor from a pipe
wall. Flow assurance solids such as hydrate can contribute to corrosion and to erosion.
Fines produced from reservoir accumulation in lines or process equipment—common
in weakly consolidated reservoirs such as deepwater Gulf or Mexico, South America
or West Africa. Usually mineral fines accumulate in locations where flow velocity is
insufficient to fluidize and carry the solids.
Flow-induced vibration or pulsation of flow line or jumper—caused by higher than
designed flow. Can occur in jumpers and locations where flow changes direction and
2
bracing is insufficient to keep the flow path rigid, usually above flow rates of 2 mbd/in.
2
or 58 GPM/in. .
Foaming—can be caused by high flow, shear, incompatible fluids, improperly mixed
chemicals. Can occur downhole, in flowlines or in process equipment.
Holdup of liquids in flow lines or in pipe lines—can be caused by flow velocity
insufficient to sweep liquids as in flow turndown scenario, or triggered by pressure
oscillations. Usually occurs in low spots and can cause terrain slugging.
Hydrate blockage—occurs in vertical, horizontal and inclined lines. Accumulates in
low spots. Occurs where five conditions are met: high pressure, low temperature,
presence of water (as liquid, vapor or ice), presence of hydrocarbon (gas or oil with
dissolved gas), and flow shear insufficient to sweep the solids. Hydrate is usually more
thermodynamically stable than ice and can form in LNG process equipment. Hydrate is
translucent and usually dissociates with bubbles when exposed to atmosphere.
Ice blockage—can occur in low-flow or dead leg line pipe. Also can happen downstream
of a flow restriction, or in flare relief lines when two streams, cold and moist, combine.
Injectivity damage for injector wells—caused by biofilm or unfiltered solids or high
dosage chemicals. Can occur over time as unfiltered solids accumulate in the injection
well perforations, or from a sudden flow rate change as solids settled in the water
injection pipeline get fluidized and transported downhole.
Joule-Thomson cooling or J-T heating of produced fluids—caused by thermodynamic
response of hydrocarbon fluid to pressure change. Saturated fluid below the bubble point
pressure experience J-T cooling upon pressure decrease. Undersaturated or supercritical
fluid experiences heating upon pressure decrease as in well flow.
Loading of wells with liquids during multiphase flow occurs when gas kinetic energy is
insufficient to overcome liquid gravity. Typically occurs when gas flow velocity is below
2 m/s or 7 ft/s but depends on interfacial entrainment of liquid by gas (related to surface
tension).