Page 119 - Handbook Of Multiphase Flow Assurance

Hydrate of natural gas 115

agglomeration. Examples of crudes with naturally occurring inhibiting properties have been
reported in the Gulf of Mexico and in the Campos basin of the Atlantic Ocean.
The amount of water becomes limiting for the deployment of an AA hydrate inhibitor as
the chemical delivery system is typically rated to supply a certain flow rate of the chemical,
based on the maximum pressure which a chemical pump can reach. Usually half-inch or 12-
mm diameter tubes are used to supply chemicals to subsea trees in deepwater application.
Other sizes such as quarter inch or 5/8 in. may be used as dictated by project economics. Once
the amount of the produced water exceeds the ability of the chemical system to deliver suffi-
cient amount of chemical (between 0.5 and 3 vol% on water basis) the chemical applicability
range is exceeded. Operator may respond either by choking back production from a well
which produces too much water or by increasing chemical injection up to the pump limit, as
dictated by economics of each response.
Time does become a limitation for AA chemicals when the threshold water cut is exceeded.
In such cases AA may provide a temporary protection from a solid blockage for several hours.
It is imperative if a production system experiences a sudden increase in produced water cut,
such as water breakthrough in a well either on water injection pressure maintenance or on
natural reservoir depletion that such production system is treated upon an eventual shut-in
with a secondary risk mitigation method such as methanol injection or bullheading of live
produced fluids using stock oil from the gathering flowline into the well to a depth which is
warmer than the hydrate stability temperature. If a secondary measure is not implemented
after the primary measure fails, a flowline blockage is likely to form. Once the blockage fully
forms, the pressure communication between the processing facility and the wellhead tree is
lost, and the ability to respond by injecting methanol, stock oil or by depressurizing disap-
pears. The temporary protection time for an AA chemical used outside its normal operating
conditions verified in a laboratory depends on few aspects: how quickly water normally dis-
persed as droplets in hydrocarbons drains from high to low spots thus creating excess water
available for hydrate formation, and how quickly hydrate solids grow and agglomerate in
the production system undertreated with an AA chemical. Hydrate can grow as rapidly as
1 mm per second in laboratory conditions at gas-water interface with sufficient cooling. In
production system the process is limited by both heat transfer (hydrate formation releases
heat) and by mass transfer (gas molecules need to diffuse from live oil to water, through a
growing layer of hydrate). Hydrate growth in stagnant conditions in cylindrical geometries
was investigated in the laboratory (Makogon, 1997). It was shown that hydrate grows more
intensively near the pipe wall, likely as a thin capillary channel between hydrate and pipe
wall provides a path for water molecules to migrate up toward hydrocarbons thus acceler-
ating the mass transfer, and proximity to the cold pipe wall surface also accelerated the heat
transfer. The hypothesis for capillary water migration may be substantiated by the coloring
of hydrate with corrosion products in the stainless steel cell where hydrate formed with de-
gassed distilled water. Increased corrosion in stainless materials observed during hydrate
formation as shown in Fig. 5.15 was mentioned earlier.
• Effect of underinhibition
In case of insufficient thermodynamic inhibitor such as glycol or methanol, hydrate will
start forming and accumulating in the process stream. Methanol leads to more solid agglom-
eration, whereas glycol leads to more slushy hydrate which can get displaced from pipeline
low spots downstream into pipeline slug catcher when flow rate increases (Dawson, 1999).