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The Ignik Sikumi #1 Well was designed for a short-duration
field trial of a potential gas hydrate production technology
(Farrell
et al.
2010; Schoderbek
et al.
2012). The approach
involves injecting carbon dioxide into gas-hydrate-bearing
sandstone reservoirs to produce a chemical exchange reaction
that releases methane gas and, at the same time, traps carbon
dioxide in a solid carbon dioxide hydrate. Operations were
conducted from temporary ice pads in the Prudhoe Bay area of
Alaska’s North Slope in the winters of 2011 and 2012.
Initially, ConocoPhillips undertook the project in collaboration
with the US Department of Energy (USDOE). Drilling began on
April 5, 2011, and in less than two weeks, the well had reached a
depth of 781metres. Wireline well logs confirmed four gas-hydrate-
bearing sand horizons. The primary test target, 675 metres below
the rig floor, was 13.4 metres thick. The well was completed and a
range of scientific monitoring devices and chemical injection and
gas-lift equipment was installed before the well was temporarily
suspended and the rig moved off location on April 28, 2011.
Early in 2012, ConocoPhillips and the USDOE returned to the
site, along with a new project partner, the Japan Oil, Gas and
Metals National Corporation (JOGMEC). Their goal was to
conduct the first field trial of carbon dioxide-methane exchange
in naturally occurring methane hydrate reservoirs (Schoderbek
et al.
2012). The field trial consisted of an initial phase of
Box 3.4
The Ignik Sikumi Gas Hydrate Field Trial
chemical injection, followed by controlled, step-wise pressure
reduction. Over a 12-day period in late February and early March,
5 950 cubic metres of blended carbon dioxide (23 per cent) and
nitrogen (77 per cent), along with small volumes of chemical
tracers, were injected into the formation. Mixed gas was used,
rather than pure carbon dioxide, to enhance opportunities for
the carbon dioxide to interact with the native methane hydrate.
Beginning on March 4, 2012, the well was operated by
pumping fluids from the wellbore. That lowered pressure
enough to draw fluids from the formation, while remaining
above the pressure that would destabilize the native methane
hydrate. Following an initial period of erratic production and
operational challenges, the well flowed continuously for the
final 19 days of the test, which ended on April 11, 2012. During
this final period, flowing reservoir pressures were smoothly
lowered and production rates steadily increased from 560
cubic metres a day to 1 280 cubic metres a day. The recovered
gas was progressively dominated by methane. Overall, the well
produced for 30 days during the 38-day flow-back period, with
cumulative gas production approaching 28 317 cubic metres.
The project team is currently working with the field data, which
have been made public. Analysis will focus on understanding
the nature of the processes active in the reservoir (Anderson
et al.
, 2014).
to prevent blockages in pipelines due to the unwanted forma-
tion of gas hydrates. While chemical injection remains an
option for dealing with flow assurance issues, its utility for
field-scale production of gas hydrates appears limited. Op-
erational considerations and the costs associated with inject-
ing large volumes of chemicals into the reservoir are major
considerations, as are the rapidly declining effectiveness of
the inhibitors (because of continuing dilution by the large
amounts of water released during the dissociation process)
and potentially overriding environmental concerns.
A new concept based on chemical processes at the molecu-
lar level has been the subject of laboratory and modelling
studies (McGrail
et al.
2007; Graue
et al.
2006; Stevens
et al.
2008). The goal is to release methane by introducing another
gas, such as carbon dioxide, which would change the chemi-
cal conditions in the reservoir and replace the native meth-
ane hydrate with carbon dioxide or other mixed gas hydrates.
This process could resolve some of the potential geomechan-
ical issues associated with other production methods and al-
low for synergistic storage of carbon dioxide. However, many
technical challenges exist (see Farrell
et al.
2009), most no-
tably the ability to inject carbon dioxide into water-bearing,
low-permeability formations. A field trial of this concept,
undertaken in Alaska in 2012, successfully employed a mix-
ture of nitrogen and carbon dioxide gas to enable injection
(Schoderbek
et al.
2012). For a summary of the field trial and
results to date, see Text Box 3.4.