Page 121 - Handbook Of Multiphase Flow Assurance

Hydrate of natural gas 117

Pressure management and wellwork safety
Combination of salt and glycol or low dosage hydrate inhibitor may be used in wells where
pressure management is important. An example is weakly consolidated formations in Western
Atlantic deepwater. In cases of very high pressure reservoirs, wells during drilling and com-
pletion need to be protected from hydrate formation at the mudline hydrostatic pressure and
mudline ambient temperature which is usually +4 °C, sometimes lower. Hydrates are a con-
cern because hydrocarbon fluid may migrate into the openhole wellbore, gas or dense phase
hydrocarbon may evolve from reservoir as hydrocarbon density is lower than that of a drilling
mud or a wellwork fluid. Gas or dense phase hydrocarbon can rise by buoyancy to the mud-
line and form a hydrate accumulation at cold temperature leading to stuck equipment.
The concentration of salt in wellwork fluid required to prevent hydrate at these conditions
can make the brine too heavy, which may make the wellwork fluid overbalanced and cause
uncontrolled fracturing of the reservoir. This may lead to uncontrolled release of hydrocar-
bons from the reservoir through the fractures to the environment. In order to avoid that, the
formulation of the wellwork fluids for weakly consolidated formations may combine salts
and glycols. Glycol adds less weight than salt to the wellwork fluid, but adds as much hy-
drate inhibition as salt. It is recommended that hydrate stability of a selected wellwork fluid
is measured in the laboratory. This is a relatively simple and fast measurement which allows
the driller to know the exact pressure at which hydrate would be stable at seabed tempera-
ture. The cost of a lab test to verify hydrate conditions with high salinity high pressure drill-
ing mud or workover fluid system is immeasurably less than that of a deepwater well or of
the undesirable consequences.
In some cases low dosage hydrate inhibitors lose their effectiveness or get poisoned by
other chemical additives present in wellwork fluids. Again the effectiveness of low dosage
hydrate inhibitors in wellwork fluids should be verified in a lab.
SCSSV safety valve has to be set deeper than the produced fluid hydrate stability depth,
using temperature distribution from undisturbed well temperature log. Regional geothermal
gradient analog may be used if accurate well log data are unavailable.

Hydrate dissociation

Hydrate dissociates when the environment is not sufficient anymore to balance the force
of guest molecules' repulsion from water and the attractive force of hydrogen bonds holding
water molecules in a lattice around the guest molecules. This occurs when one or more of the
three events take place: pressure is reduced, temperature is increased, or water molecules are
dissolved into a solvent. The fourth method for a direct removal of guest molecules from the
hydrate lattice has not been invented yet.
The presence of additives such as kinetic hydrate inhibitors had been shown (Makogon
et al., 2000; Makogon and Holditch, 2001a) to cause a hysteresis in hydrate dissociation,
when higher temperature was required to dissociate hydrate formed with KHI. Makogon
and Holditch (2001b) reported up to 8.2 °C higher temperature of complete dissociation with
0.5% kinetic inhibitor. The temperature was increased very slowly at 1 °C/day or less. It
was hypothesized that KHI molecules adsorbed to the hydrate surface stabilize it like steel
bars would stabilize a concrete wall, and also decreased the water vapor pressure above the
hydrate.