Page 115 - Handbook Of Multiphase Flow Assurance

Hydrate of natural gas 111

to restart process equipment (consult with operations representative). Pipeline with gas filled
state should be assumed for cooldown calculations, and hydrate curve for condensed (fresh)
water should be used to determine cooldown time.
For high acid gas content (>2 mol% H 2 S or CO 2 ), high salinity (>100,000 TDS) and high
pressures (>10,000 psi) lab measurements should be used to verify hydrate stability condi-
tions. Hydrate formation metastability and underinhibition should not be relied upon in nor-
mal operations.
On start-up, system should be thermally or chemically treated until system temperature
increases sufficiently to provide a safe-out time plus a no-touch time before re-entering hy-
drate conditions during an aborted start-up. For systems with on-demand active heating only
temperature of components without heating (jumpers, trees, risers) should be considered.
For flow assurance risk management strategies, minimum water cut threshold for chem-
ical treatment such as 1% may be used if supported by appropriate multiphase laboratory
verification (flow loop or flow wheel) and by multiphase modeling to ensure that all formed
hydrate is fully dispersed and does not accumulate when water cut is less than 1%. Partial gas
separation may be used to avoid hydrate if supported by appropriate laboratory verification.
Several methods for hydrate prevention may be used:
Thermal methods
Thermal insulation or line burial is used in onshore and subsea production systems. When
the produced fluids remain outside the hydrate stability envelope throughout the whole length
of the production system, the use of hydrate inhibitor chemicals is unnecessary. In some cases
the insulation is used to prevent wax deposition and thus hydrate also gets prevented as the
temperature of hydrate stability is usually lower than the temperature of wax stability.

Dehydration
To prevent or to shift hydrate stability before it forms, the amount of water may be reduced
in a flowing gas stream. Typical dehydration of gas is to 6–7 pounds of water per million
standard cubic feet of gas. Modern equipment allows to achieve dehydration to 1–2 pounds
per MMSCF.
Similar to gas dehydration, a partial or complete water removal from oil systems may help
achieve the hydrate blockage-free production to a level where remaining water can be trans-
ported with the reservoir fluid, with or without the use of chemicals. Alternative to partial wa-
ter removal may be partial gas removal from low GOR systems. If the amount of hydrate which
forms after a partial gas removal can be transported with the reservoir fluid, with or without
the use of chemicals, this approach may also help achieve the hydrate blockage-free production.

Chemical inhibition
Chemical inhibition serves the same purpose as dehydration: to prevent hydrate block-
ages. A variety of chemicals exist, in two broad categories these are thermodynamic inhibitors
and low dosage hydrate inhibitors (LDHI). Thermodynamic inhibitors act by altering water.
Low dosage inhibitors work by altering hydrate crystals.
• Thermodynamic inhibitors
Thermodynamic inhibitors connect to water molecules either by hydrogen bonds like al-
cohols as shown in Fig. 5.12 and glycols or by ionic bonds like salt ions as shown in Fig. 5.13.