The amount of methane sequestered
in gas hydrates is probably enormous, but estimates of the amounts are
speculative and range over three orders-of-magnitude from about 3,114
to 7,634,000 trillion cubic meters (reviewed by Kvenvolden, 1993). It
is likely, however, that the amount of gas in the hydrate reservoirs of
the world greatly exceeds the volume of known conventional gas reserves.
Before reviewing assessments of the world gas hydrate resources it is
necessary to examine the quality and variability of gas hydrate assessments
at the accumulation and reservoir scale.
Gas
Hydrates at the Reservoir and Accumulation Scale
Estimates of the amount of
gas hydrates and associated gas within a given gas hydrate accumulation
can vary considerably. For example, recent estimates of the volume of
gas that may be contained in the gas hydrates and free-gas beneath the
gas hydrates on the Blake Ridge range from about 70 trillion cubic meters
of gas over an area of 26,000 km2 (Dickens et al., 1997) to
about 80 trillion cubic meters of gas for an area of 100,000 km2 (Holbrook et al., 1996). The difference between these two estimates has
been attributed to the observation that the amount of free-gas directly
measured within pressure-core samples (Dickens et al., 1997) from beneath
the gas hydrates is significantly larger than that estimated from borehole
vertical seismic profile data (Holbrook et al., 1996). Other published
studies indicate that the gas hydrates at the crest of the Blake Ridge
alone (area of about 3,000 km2) may contain more than 18 trillion
cubic meters of gas (Dillon and Paull, 1983). The broad range of these
estimates demonstrates the need for high-resolution measurements of the
gas hydrate and associated free-gas volumes within any gas hydrate accumulation
of interest.
It has been suggested that
the volume of gas that may be contained in a gas hydrate accumulation
depends on five "reservoir" parameters (modified from Collett,
1993): (1) areal extent of the gas-hydrate occurrence, (2) "reservoir"
thickness, (3) sediment porosity, (4) degree of gas-hydrate saturation,
and (5) the hydrate gas yield volumetric parameter which defines how much
free-gas (at STP) is stored within a gas hydrate (also known as the hydrate
number). In the following section, the five "reservoir" parameters
(Table 1) needed to calculate the volume of gas associated with the gas
hydrates on the Blake Ridge (ODP Sites 994, 995, and 997; Shipboard Scientific
Party, 1996), along the Cascadia continental margin (ODP Site 889; Shipboard
Scientific Party, 1994), on the North Slope of Alaska (Northwest Eileen
State-2 well; Collett, 1993), and in the Mackenzie River Delta of Canada
(Mallik 2L-38 well; Dallimore et al., 1999) are assessed.
The following "resource"
assessment (modified from Collett, 1998) has been conducted on a site-by-site
basis; that is, for each site examined the volume of gas hydrate and associated
gas within a one square kilometer area surrounding each drill-site have
been individually calculated (Table 1). For this "resource"
assessment, I have defined the thickness of the gas-hydrate-bearing sedimentary
section at both the marine and permafrost drill sites to be the total
thickness of the downhole log inferred gas-hydrate accumulation (Table
1). Average core derived sediment porosities for the gas-hydrate-bearing
reservoirs at Sites 994, 995, 997 and 889 range from about 52 to 58 percent
(Table 1). The "corrected" density log derived sedimentary
porosities for the three gas-hydrate-bearing units identified in the Northwest
Eileen State-2 (Units C, D, and E) range from an average value of about
36 to 39 percent (Table 1). The density log derived sediment porosities
for the gas-hydrate-bearing interval in the Mallik 2L-38 well averages
about 31% (Table 1). Gas-hydrate saturations at the marine drill-sites
(Sites 994, 995, 997 and 889), calculated from available downhole logs,
range from an average value of about 3 to 6 percent (Table 1). Gas-hydrate
saturations in all three gas-hydrate-bearing units (Units C, D, and E)
in the Northwest Eileen State-2 well, calculated from available downhole
log data, range from an average value of about 33 to 61 percent (Table
1). The resistivity well log derived gas-hydrate saturations in the Mallik
2L-38 well average about 44% (Table 1). In this assessment, I have assumed
a hydrate number of 6.325 (90% gas filled clathrate) which corresponds
to a gas yield of 164 m3 of methane (at STP) for each cubic
meter of gas hydrate. The log inferred gas hydrates at Sites 994, 995,
and 997 on the Blake Ridge contain between 670,000,000 and 1,450,000,000
cubic meters of gas per square kilometer (Table 1). The volume of gas
within the log inferred gas hydrates at Site 889 on the Cascadia continental
margin is about 467,000,000 cubic meters of gas per square kilometer (Table
1). Cumulatively, all three log inferred gas-hydrate-bearing stratigraphic
units (Units C, D, and E) drilled and cored in the Northwest Eileen State-2
well may contain about 1,511,000,000 cubic meters of gas in the one square
kilometer area surrounding this drill-site (Table 1). It was also determined
that the log inferred gas-hydrate-bearing stratigraphic interval drilled
in the Mallik 2L-38 well contains about 4,750,000,000 cubic meters of
gas in the one square kilometer area surrounding the Mallik drill-site
(Table 1).
A close examination of the
gas hydrate saturations in Table 1 reveals a potential problem associated
with production of gas from marine gas hydrates. Even though vast portions
of the world’s continental shelves appear to be underlain by gas hydrates,
the concentration of hydrates within most marine accumulations appears
to be very low. Low gas hydrate concentrations may significantly affect
the economic production potential of marine gas hydrates (gas hydrate
production is discussed in more detail later in this paper).
Gas
Hydrates at the World and National Scale
World estimates for the amount
of natural gas in gas hydrate deposits range from 14 to 34,000 trillion
cubic meters for permafrost areas and from 3,100 to 7,600,000 trillion
cubic meters for oceanic sediments (modified from Kvenvolden, 1993).
The estimates in Table 2 show considerable variation, but oceanic sediments
seem to be a much greater resource of natural gas than continental sediments.
Current estimates of the amount of methane in the world’s gas hydrate
accumulations are in rough accord at about 20,000 trillion cubic meters
(reviewed by Kvenvolden, 1993). If these estimates are valid, the amount
of methane in gas hydrates is almost two orders of magnitude larger than
the estimated total remaining recoverable conventional methane resources,
estimated to be about 250 trillion cubic meters (Masters et al., 1991).
The recently completed 1995
National Assessment of United States Oil and Gas Resources, conducted
by the U.S. Geological Survey, focused on assessing the undiscovered conventional
and unconventional resources of crude oil and natural gas in the United
States (Gautier et al., 1995). This assessment included for the first
time a systematic resource appraisal of the in-place natural gas hydrate
resources of the United States onshore and offshore regions (Collett,
1995). In this assessment, 11 gas-hydrate plays were identified within
four offshore and one onshore gas hydrate provinces. The offshore gas
hydrate provinces assessed lie within the U.S. Exclusive Economic Zone
adjacent to the lower 48 States and Alaska. The only onshore province
assessed was the North Slope of Alaska. In-place gas resources within
the gas hydrates of the United States are estimated to range from about
3,200 to 19,000 trillion cubic meters of gas, at the 0.95 and 0.05 probability
levels, respectively. Although this wide range of values shows a high
degree of uncertainty, it does indicate the potential for enormous quantities
of gas stored as gas hydrates. The mean in-place value for the entire
United States is calculated to be about 9,000 trillion cubic meters of
gas.
Gas
Hydrate Production Technology
Even though gas hydrates are
known to occur in numerous marine and Arctic settings, little is known
about the technology necessary to produce gas hydrates. Most of the existing
gas hydrate "resource" assessments do not address the problem
of gas hydrate recoverability. Proposed methods of gas recovery from
hydrates (Figure 18) usually deal with dissociating or "melting"
in-situ gas hydrates by (1) heating the reservoir beyond hydrate formation
temperatures, (2) decreasing the reservoir pressure below hydrate equilibrium,
or (3) injecting an inhibitor, such as methanol or glycol, into the reservoir
to decrease hydrate stability conditions. Gas recovery from hydrates
is hindered because the gas is in a solid form and because hydrates are
usually widely dispersed in hostile Arctic and deep marine environments.
First order thermal stimulation computer models (incorporating heat and
mass balance) have been developed to evaluate hydrate gas production from
hot water and steam floods, which have shown that gas can be produced
from hydrates at sufficient rates to make gas hydrates a technically recoverable
resource (Sloan, 1998). However, the economic cost associated with these
types of enhanced gas recovery techniques would be prohibitive. Similarly,
the use of gas hydrate inhibitors in the production of gas from hydrates
has been shown to be technically feasible (Sloan, 1998), however, the
use of large volumes of chemicals such as methanol comes with a high economic
and environmental cost. Among the various techniques for production of
natural gas from in-situ gas hydrates, the most economically promising
method is considered to be the depressurization technique. However, the
extraction of gas from a gas hydrate accumulation by depressurization
may be hampered by the formation of ice and/or the reformation of gas
hydrate due to the endothermic nature of gas hydrate dissociation.
The Messoyakha gas field in
the northern part of the West Siberian Basin is often used as an example
of a hydrocarbon accumulation from which gas has been produced from in-situ
natural gas hydrates. Production data and other pertinent geologic information
have been used to document the presence of gas hydrates within the upper
part of the Messoyakha field (Makogon, 1981). It has also been suggested
that the production history of the Messoyakha field demonstrates that
gas hydrates are an immediate producible source of natural gas, and that
production can be started and maintained by conventional methods. Long-term
production from the gas-hydrate part of the Messoyakha field is presumed
to have been achieved by the simple depressurization scheme. As production
began from the lower free-gas portion of the Messoyakha field in 1969,
the measured reservoir-pressures followed predicted decline relations;
however, by 1971 the reservoir pressures began to deviate from expected
values. This deviation has been attributed to the liberation of free-gas
from dissociating gas hydrates. Throughout the production history of
the Messoyakha field, it is estimated that about 36% (about 5 billion
cubic meters) of the gas withdrawn from the field has come from the gas
hydrates (Makogon, 1981). Recently, however, several studies suggest
that gas hydrates may not be significantly contributing to gas production
in the Messoyakha field (reviewed by Collett and Ginsburg, 1998).
It should be noted, that our
current assessment of proposed methods for gas hydrate production do not
consider some of the more recently developed advanced oil and gas production
schemes. For example, the usefulness of downhole heating methods such
as in-situ combustion, electromagnetic heating, or downhole electrical
heating have not been evaluated. In addition, advanced drilling techniques
and complex downhole completions, including horizontal wells and multiple
laterals, have not been considered in any comprehensive gas hydrate production
scheme. Gas hydrate provinces with existing conventional oil and gas
production may also provide us with the opportunity to test relatively
more advanced gas hydrate production methods. For example, in northern
Alaska existing "watered-out” production wells are being evaluated
as potential sources for hot geopressured brines that will be used to
thermally stimulate gas hydrate production.
As previously noted, the low
concentration of hydrates in most of the world’s marine gas hydrate occurrences
raises a concern over the production technology required to produce gas
from highly disseminated gas hydrate accumulations. In addition, the
host-sediments also represent a significant technical challenge to potential
gas hydrate production. In most cases, marine gas hydrates have been
found in clay-rich unconsolidated sedimentary sections that exhibit little
or no permeability. Most of the existing gas hydrate production models
require the establishment of reliable flow paths within the formation
to allow the movement of produced gas to the wellbore and injected fluids
into the gas-hydrate-bearing sediments. It is unlikely, however, that
most marine sediments possess the mechanical strength to allow the generation
of significant flow paths. It is possible that in basins with significant
input of coarse-grained clastic sediments, such as the Gulf of Mexico
or along the eastern margin of India, gas hydrates may be reservoired
at high concentrations in more conventional clastic reservoirs; which
is more analogous to the nature of gas hydrate occurrences in onshore
permafrost environments (Collett, 1993; Dallimore et al., 1999).