Summary
Gas-hydrate inhibition is a serious concern for operators producing at
conditions in the hydrate region. As production goes into deeper water, hydrate
control grows in importance. Ideally, operators want total hydrate control
without the problems associated with thermodynamic inhibitors (THI) and/or
low-dose hydrate inhibitors (LDHI). A Gulf of Mexico (GOM) operator experienced
hydrate-control problems in an 18,000-ft umbilical line in spite of the
addition of methanol as a thermodynamic hydrate inhibitor. In addition to
erratic pressure, the high rates of methanol usage created a logistical problem
as well as a health, safety, and environmental (HS&E) concern because of
the handling issues associated with methanol.
Laboratory studies and previous onshore field experience indicated that
hydrate-inhibition synergy is gained through the combination of thermodynamic
inhibitors and LDHI (Budd et al. 2004). This is termed a hybrid hydrate
inhibitor (HHI). Because of the performance, logistical, and cost drivers
presented by the use of methanol, any alternative approach must consider those
three factors. The performance has to do with hydrate dissolution in the event
a hydrate formed during operations. A kinetic inhibitor (KHI) can prevent
hydrate formation but cannot dissolve already formed hydrates. Antiagglomerant
(AA) inhibitors allow hydrates to form but keep the hydrate particles dispersed
in the fluids. The logistics have to do with pump sizing (i.e., conventional
LDHI applications require new pumps and configurations). The cost of methanol
is far less than specialty LDHI chemistry. Thus, the objective of the study is
to provide all the benefits of the existing technology with improved
performance, improved logistics, and at a cost not to exceed hydrate prevention
with methanol.
After a presentation of lab and field studies to the operator, a method of
application was approved for use. The differential pressure (Dp) between
the wellhead pressure (chemical injection line) and the flowline pressure
serves as the key performance metric. There is a significant decrease of
Dp after the HHI product is introduced into the system. Initially, the
HHI is applied at the same rate (and a much higher equivalent cost) as
methanol. After saturation of the system, the inhibitor rate is decreased in a
stepwise fashion until the daily costs of treatment fall below the daily cost
of methanol. On a cost-performance basis, the new product outperforms the
methanol. While the methanol rate is 120 gal/D, the new product controls line
pressure at a rate as low as 12 gal/D. The HHI dosage is eventually set at 22
gal/D to compensate for potential flow and pressure/temperature fluctuations.
From the logistical standpoint, methanol shipments to the platform decreased
five-fold. This decrease meant less cost and handling as well as a reduction in
the footprint for product storage. From an HS&E position, the potential for
an incident is decreased in line with the reduction in boat trips and crane
lifts.
The technology described in this paper created a synergy that assuages the
concerns of operations, technical, logistics, HS&E, and personnel. After
observing that hydrate dissolution is still possible at a lower dosage with
less handling and at a comparable cost, the HHI treatment became a permanent
hydrate prevention method. The project is a success with possible future
expansion.
Introduction
Gas hydrates form when water molecules crystallize around guest molecules.
The water/guest crystallization process has been recognized for several years,
is well characterized, and occurs with sufficient combinations of temperature
and pressure (Katz 1945). Light hydrocarbons, methane-to-heptanes, nitrogen,
carbon dioxide, and hydrogen sulfide are the guest molecules of interest to the
natural-gas industry. Depending on the pressure and gas composition, gas
hydrates may build up at any place in which water coexists with natural gas at
temperatures as high as 80°F [~30°C]. Gas-hydrate formation is a growing
problem because producers drill in deeper waters and in cooler waters. The
hydrates can form in a wellbore while the fluids go through pressure- and
temperature-induced phase changes near the mud line. The hydrates also form in
the flowlines from subsea completions to the separation facilities. The problem
of finding an effective hydrate control method in a system at hydrate
conditions is especially difficult in offshore environments where one has no
control over the fluid composition, bottomhole pressure, and temperature. The
well operator has only a limited control over the wellhead pressure. The
producing formation temperature, Joule-Thomson cooling effect upon gas
decompression, and heat loss to the environment are the factors deciding if a
particular well or flowlines are at hydrate forming conditions. Hydrates create
physical barriers to production and must be inhibited and dissolved if formed
for gas production to occur. The operator must maintain the well and production
lines free of hydrates at all times.
© 2006. Society of Petroleum Engineers
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History
- Original manuscript received:
7 October 2005
- Revised manuscript received:
5 April 2006
- Manuscript approved:
11 September 2006
- Version of record:
20 December 2006
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