Page 43 - Handbook Of Multiphase Flow Assurance

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

Mercury accumulation in flow lines, process equipment and product streams—occurs
where mercury or organomercury is not soluble in the produced stream, usually at low
temperature. Mercury is a shiny liquid. Organomercury is clear volatile liquid, strong
neurotoxin and easily penetrates some PPE such as latex gloves. Mercury compounds in
hydrocarbons commonly occur in continental rim areas.
Naphthenates deposition in flow lines and process equipment occurs when produced
fluids have both natural acids dissolved in oil and metals such as calcium dissolved in
water. Deposits are highly viscous.
Oil quality noncompliance due to water content—occurs in surface process equipment
due to insufficient residence time or insufficient temperature to resolve water-in-oil
emulsion.
Productivity damage for producer wells—occurs when solids or liquids adsorb on
rock surface and reduce the pores cross section area and permeability. Deposits may be
organic such as asphaltenes, heavy oil fractions and inorganic such as sand or scale. Flow
shear and pressure drop caused by higher flow velocity in the near-wellbore zone may
cause asphaltenes precipitation. Subsequent well workover with an acid may further
destabilize asphaltenes.
Sand deposition in lines, process equipment or valves. Sand can be produced from
wells where rock consolidation or cementing was lost, such as in wells ramped up
quickly, or wells which have experienced reverse flow (bullheading) through a gravel-
pack completion. Cementing of sand grains in near-wellbore zone can be lost during
production of gas hydrate deposits where hydrate was the cementing agent but
dissociated to recover natural gas. Also cementing can be lost in regular oil or gas wells
if a chemical which can dissolve water such as methanol or methanol-based chemical is
pumped to and stays in the perforations. Methanol dehydrates rock, and sand production
may start or productivity damage may occur.
Scale deposition and scale products accumulation in flow line and process equipment—
happens when temperature, pressure and composition of both produced hydrocarbons
and produced water are such that all mineral dissolved in water at reservoir conditions
cannot remain dissolved in water at wellbore, flowline or separator conditions. Seawater
injection can cause barite scale deposition. Barite has toxic barium ions but is nearly
insoluble in water so does not affect health. Barium carbonate scale is toxic and strontium
sulfate scale can be radioactive.
Slugging: severe (terrain-induced) and hydrodynamic (gas flow-induced)—results in
significant pressure oscillations and in impacts of liquid slugs at bends and process
equipment. Typically occurs in near-horizontal gas and gas condensate production
both onshore and subsea, and in horizontal-come-vertical flow geometries such as in
deepwater multiphase tiebacks and in shale horizontal well production. Terrain-induced
or severe slugging is caused by insufficient energy of gas to lift liquids from a low spot
such as riser base, similar to well liquid loading. Hydrodynamic slugging occurs during a
change in gas flowrate (usually ramp-up or increase) when gas at higher velocity sweeps
liquid from its steady-state holdup locations and brings the surge of liquid to a bend or to
an outlet. Slugging can occur with time period of minutes to days.
Souring of produced fluids can occur when water injected into the reservoir to maintain
reservoir pressure brings sulphates which is food for sulfate-reducing bacteria present in