As noted in the introduction,
the remaining portion of this paper deals with the assessment of the geologic,
engineering, economic, and political factors that control the ultimate
resource potential of gas hydrates.
Where
Do Gas Hydrates Occur?
The geologic occurrence of
gas hydrates has been known since the mid-1960s, when gas-hydrate accumulations
were discovered in Russia (reviewed by Makogon, 1981). As discussed in
the previous section of this paper, gas hydrates are widespread in permafrost
regions and beneath the sea in sediment of outer continental margins (reviewed
by Kvenvolden, 1993). Cold surface temperatures at high latitudes on
earth are conducive to the development of onshore permafrost and gas hydrate
in the subsurface. Onshore gas hydrates (Figure 4) are known to be present
in the West Siberian Basin (Makogon et al., 1972) and are believed to
occur in other permafrost areas of northern Russia, including the Timan-Pechora
province, the eastern Siberian Craton, and the northeastern Siberia and
Kamchatka areas (Cherskiy et al., 1985). Permafrost-associated gas hydrates
are also present in the North American Arctic. Direct evidence for gas
hydrates on the North Slope of Alaska comes from a core-test in the Northwest
Eileen State-2 well, and indirect evidence comes from drilling and open-hole
industry well logs that suggest the presence of numerous gas hydrate layers
in the area of the Prudhoe Bay and Kuparuk River oil fields (as discussed
previously in this paper). Well-log responses attributed to the presence
of gas hydrates have been obtained in about one-fifth of the wells drilled
in the Mackenzie Delta, and more than half of the wells in the Arctic
Islands are inferred to contain gas hydrates (Judge and Majorowicz, 1992).
The recently completed Mallik 2L-38 gas hydrate research well, confirmed
the presence of a relatively thick, highly concentrated, gas hydrate accumulation
on Richards Island in the outer portion of the Mackenzie River Delta (Dallimore
et al., 1999).
The presence of gas hydrates
in offshore continental margins (Figure 4) has been inferred mainly from
anomalous seismic reflectors (i.e., BSRs) that coincide with the predicted
phase boundary at the base of the gas-hydrate stability zone. Gas hydrates
have been recovered in gravity cores within 10 m of the sea floor in sediment
of the Gulf of Mexico (Brooks et al., 1986), the offshore portion of the
Eel River Basin of California (Brooks et al., 1991), the Black Sea (Yefremova
and Zhizhchenko, 1974), the Caspian Sea (Ginsburg et al., 1992), and the
Sea of Okhotsk (Ginsburg et al., 1993). Also, gas hydrates have been
recovered at greater sub-bottom depths during research coring along the
southeastern coast of the United States on the Blake Ridge (Kvenvolden
and Barnard, 1983; Shipboard Scientific Party, 1996), in the Gulf of Mexico
(Shipboard Scientific Party, 1986), in the Cascadia Basin near Oregon
(Shipboard Scientific Party, 1994), the Middle America Trench (Kvenvolden
and McDonald, 1985), offshore Peru (Kvenvolden and Kastner, 1990), and
on both the eastern and western margins of Japan (Shipboard Scientific
Party, 1990, 1991).
How
Do Gas Hydrates Occur in Nature?
Little is known about the nature
of gas hydrate reservoirs. For example, do hydrates occur as pore-filling
constituents or are they only found in massive form (Figure 15). Information
about the nature and texture of reservoired gas hydrates is needed to
accurately determine the amount of gas hydrate and associated gas in a
given gas hydrate accumulation. The textural nature of gas hydrate in
the reservoir also controls the production potential and characteristics
of a gas hydrate accumulation. The physical and chemical conditions that
result in different forms (disseminated, nodular, layered, massive) and
distributions (uniform or heterogeneous) of gas hydrates are not understood
(reviewed by Sloan, 1998). It is necessary, therefore, to systematically
review descriptions of known gas hydrate occurrences and evaluate existing
gas hydrate reservoir models at both microscopic and macroscopic scales
in order to assess the nature of gas-hydrate-bearing reservoirs. This
section of the paper begins with a review of published gas hydrate sample
descriptions from both marine and permafrost environments, which is followed
by an interpretive discussion of existing and proposed microscopic and
macroscopic gas hydrate reservoir models.
Recovered
Gas Hydrate Samples
For this review of the nature
of gas hydrate occurrences, I have relied extensively on the offshore
gas hydrate sample database recently published by Booth et al. (1996).
In this database, Booth et al. (1996) systematically review and describe
more than 90 marine gas hydrate samples recovered from 15 different geologic
regions. The individual descriptions of the gas hydrate occurrences include
information on the number of recovered samples, physiographic province,
tectonic setting, geographic position, water depth, sub-sea-floor depth
of the recovered sample, geothermal gradient and temperature conditions,
depth to the base of the gas hydrate stability zone, presence of a bottom
simulating seismic reflector, thickness of the gas-hydrate-bearing sedimentary
interval, thickness and size of pure gas hydrate layers and grains, habit
or mode of occurrence, host sediment lithologic description, and the origin
of the included gas.
In general, most of the recovered
gas hydrate samples consist of individual grains or particles, which are
often described as inclusions or disseminated in the sedimentary section
(Figure 15). Gas hydrates also occur as, what has been described as,
a cement, nodules, or as laminae and veins, which tend to be characterized
by dimensions of a few centimeters or less. In several cases, thick,
pure gas hydrate layers measuring as much as 3- to 4-m-thick have been
sampled (DSDP Site 570; Shipboard Scientific Party, 1985). In both marine
and terrestrial permafrost environments, the thickness of identified gas-hydrate-bearing
sedimentary sections varies from a few centimeters to as much as 30 m
(Collett, 1993; Booth et al., 1996; Dallimore et al., 1999). Most pure
gas hydrate laminae and layers, however, are often characterized by thicknesses
of millimeters to centimeters (Booth et al., 1996; Dallimore and Collett,
1995; Dallimore et al., 1999). Booth et al. (1996) conclude that gas-hydrate-bearing
sedimentary sections tend to be tens of centimeters to tens of meters
thick, but thick zones of pure hydrate are relatively rare and only represent
a minor constituent of potential gas hydrate accumulations.
The
Booth et al. (1996) review along with recently published gas hydrate sample
descriptions from the Mackenzie Delta (Dallimore and Collett, 1995; Dallimore
et al., 1999) and the Blake Ridge (ODP Leg 164, Shipboard Scientific Party
1996), confirm that gas hydrates are usually uniformly distributed within
sediments as mostly pore-filling constituents.
Gas Hydrate Reservoir Models
Most
discussions on the nature or texture of gas hydrate occurrences deal with
macroscopic issues (reviewed by Booth et al., 1996). However, information
on the occurrence of gas hydrates at the pore-scale are needed, since
many gas hydrate reservoir physical properties are controlled by microscopic
parameters (Dvorkin and Nur, 1993). Of particular concern is the acoustic
nature and the fluid-flow permeability characteristics of gas-hydrate-bearing
sediments (Lee et al., 1993; Dvorkin and Nur, 1993).
Dvorkin and Nur (1993) along
with Ecker et al. (1996) have proposed and examined two "micromechanical"
models that represent the two extreme cases of gas hydrate occurrence
at the pore-scale: (Model-1) gas hydrate cement grain contacts and increases
the stiffness of the sediment; and (Model-2) gas hydrate is located away
from grain contacts in the "bulk" pore volume, and it does not
affect the stiffness of the sediment frame. Dvorkin and Nur (1993) experimentally
demonstrated that even small amounts of intergranular cementation, such
as proposed by gas hydrate Model-1, can dramatically increase the stiffness
of granular material. Dvorkin and Nur (1993) used the intergranular gas
hydrate cementation model (Model-1) to explain the occurrence of seismic
bottom-simulating-reflectors (BSR's), which they attributed to a strong
increase of the elastic moduli of the rock due to the occurrence of gas
hydrates at the base of the gas hydrate stability zone. Ecker et al.
(1996) amplitude-versus-offset (AVO) analyses of the BSR on the Blake
Ridge, however, concluded that only reservoir Model-2 could qualitatively
reproduce the observed BSR, and that gas hydrates at the pore-scale are
located away from the intergranular contacts, in large pores. Ecker et
al. (1996) further concluded that the sediment above the BSR is uncemented
and mechanically weak. However, they do not explain the acoustic parameters
that control the occurrence of the BSR on the Blake Ridge. At this time,
we must consider the conclusions of Dvorkin and Nur (1993) and Ecker et
al. (1996) preliminary until additional laboratory field observations
become available.
Before attempting to assess
the volume of gas hydrate in a particular reservoir, we need to develop
and define a series of reservoir models for the occurrence of gas hydrates
in nature. Most reservoir models are based on simple mixing rules, where
complex multi-component systems consist of simple mixtures of rock matrix
(consisting of quartz, calcite, and/or clay), water (including clay-bound-
and free-water), and hydrocarbons (gas and/or oil). In permafrost and
relatively deep marine environments, however, other reservoir constituents
can include gas hydrates and permafrost ice. The first two reservoir
models to be considered represent complex gas-hydrate-bearing reservoirs
both below (Model A; Figure 16a) and above (Model B; Figure 16b) the base
of ice-bearing permafrost in a terrestrial setting. In both of these
models the sediment matrix consists of a simple mixture of quartz, calcite,
and a relatively small amount of clay. Gas hydrate reservoir Models A
and B assume no free-gas phase, since all of the available gas is in the
gas hydrate. The only difference between Models A and B is that Model
B assumes that all of the free-water and some of the clay-bound-water
are frozen. Reservoir Model C (Figure 16c) has been designed to represent
a clay-rich marine gas hydrate reservoir. Reservoir Models C and A are
similar, but Model C assumes the clay content of the sediment and associated
volume of bound-water are higher in most marine gas-hydrate reservoirs.
The last gas hydrate reservoir model to be considered may not occur in
nature. Reservoir Model D (Figure 4d) assumes that a free-gas phase exists,
and that all of the available water is included in the gas hydrate. Water,
being relatively abundant in nature, should not be a gas hydrate limiting
factor in most reservoirs.
Why
Do Gas Hydrates Occur in a Particular Setting?
Review of previous gas hydrate
studies indicates that the formation and occurrence of gas hydrates is
controlled by formation temperature, formation pore-pressure, gas chemistry,
pore-water salinity, availability of gas and water, gas and water migration
pathways, and the presence of reservoir rocks and seals (reviewed by Collett,
1995). In the following section, these geologic controls on the stability
and formation of gas hydrates are reviewed and assessed.
Formation-Temperature,
Formation Pore-Pressure, Gas Chemistry
Gas hydrates exist under a
limited range of temperature and pressure conditions such that the depth
and thickness of the zone of potential gas-hydrate stability can be calculated.
Depicted in the temperature/depth plot of Figure 17 are a series of subsurface
temperature profiles from an onshore permafrost area and two laboratory-derived
gas-hydrate stability curves for different natural gases (modified from
Holder et al., 1987). This gas-hydrate phase-diagram (Figure 17) illustrates
how variations in formation-temperature and gas composition can affect
the thickness of the gas-hydrate stability zone. In Figure 17, the mean-annual
surface temperature is assumed to be -10°C; however, the depth to the
base of permafrost (0°C isotherm) is varied for each temperature profile
(assumed permafrost depths of 305 m, 610 m, and 914 m). Below permafrost,
three different geothermal gradients (4.0°C/100 m, 3.2°C/100 m, and 2.0°C/100
m) are used to project the sub-permafrost temperature profiles. The two
gas-hydrate stability curves represent gas hydrates with different gas
chemistries. One of the stability curves is for a 100% methane hydrate,
and the other is for a hydrate that contains 98% methane, 1.5% ethane,
and 0.5% propane.
The zone of potential gas-hydrate
stability in Figure 17 lies in the area between the intersections of the
geothermal gradient and the gas-hydrate stability curve. For example,
in Figure 17, which assumes a hydrostatic pore-pressure gradient, the
temperature profile projected to an assumed permafrost base of 610 m intersects
the 100% methane-hydrate stability curve at about 200 m, thus marking
the upper boundary of the methane-hydrate stability zone. A geothermal
gradient of 4.0°C/100 m projected from the base of permafrost at 610 m
intersects the 100% methane-hydrate stability curve at about 1,100 m;
thus, the zone of potential methane-hydrate stability is approximately
900 m thick. However, if permafrost extended to a depth of 914 m and
if the geothermal gradient below permafrost is 2.0°C/100 m, the zone of
potential methane-hydrate stability would be approximately 2,100 m thick.
Most gas-hydrate stability
studies assume that the pore-pressure gradient is hydrostatic (9.795 kPa/m;
0.433 psi/ft). Pore-pressure gradients greater than hydrostatic will
correspond to higher pore-pressures with depth and a thicker gas-hydrate
stability zone. A pore-pressure gradient less than hydrostatic will correspond
to a thinner gas-hydrate stability zone. For example, in Figure 17, which
assumes a hydrostatic (9.795 kPa/m; 0.433 psi/ft) pore-pressure gradient,
the thickness of the 100% methane-hydrate stability zone with a 610 m
permafrost depth and a sub-permafrost geothermal gradient of 2.0°C/100
m would be about 1,700 m. However, if a pore-pressure gradient of 11.311
kPa/m (0.500 psi/ft) is assumed, the thickness of the methane-hydrate
stability zone would be increased to about 1,850 m.
The gas-hydrate stability curves
in Figure 17 were obtained from laboratory data published in Holder et
al. (1987). The addition of 1.5% ethane and 0.5% propane to the pure
methane gas system shifts the stability curve to the right, thus deepening
the zone of potential gas-hydrate stability. For example, assuming a
hydrostatic pore-pressure gradient (Figure 17), a permafrost depth of
610 m, and a sub-permafrost geothermal gradient of 4.0°C/100 m, the zone
of potential methane (100% methane) hydrate stability would be about 900
m thick; however, the addition of ethane (1.5%) and propane (0.5%) would
thicken the potential gas-hydrate stability zone to 1,100 m.
Pore-Water
Salinity
Salt, such as NaCl, when added
to a gas-hydrate system, lowers the temperature at which gas hydrates
form. Pore-water salts in contact with the gas during gas hydrate formation
can reduce the crystallization temperature by about 0.06°C for each part
per thousand (ppt) of salt (Holder et al., 1987). Therefore, a pore-water
salinity similar to that of seawater (32 ppt) would shift the gas-hydrate
stability curves in Figure 17 to the left about 2°C and reduce the thickness
of the gas-hydrate stability zone.
Availability
of Gas and Water
Most naturally occurring gas
hydrates are characterized by two crystal structures known as Structure
I and Structure II (reviewed by Sloan, 1998). The ideal gas/water ratio
of Structure I gas hydrate is 8/46, whereas the ideal gas/water ratio
of Structure II gas hydrate is 24/136. These ideal ratios confirm the
observation that gas hydrates contain a substantial volume of gas. The
ideal hydrate gas/water ratios also indicate that there is a substantial
amount of water stored in the gas-hydrate structure. These high gas and
water concentrations demonstrate that the formation of gas hydrate requires
a large source of both gas and water. Thus, it becomes necessary to quantify
the potential sources of gas and water when assessing a potential gas-hydrate
accumulation. In previous studies, this evaluation is based on assessing
a set of minimum source-rock criteria that includes organic richness (total
organic carbon), sediment thickness, and thermal maturity. It has been
shown that the availability of large quantities of hydrocarbon gas from
both microbial and thermogenic sources is an important factor controlling
the formation and distribution of natural gas hydrates (Kvenvolden, 1988;
Collett, 1993). Carbon isotope analyses indicate that the methane in
many oceanic hydrates is derived from microbial sources. However, molecular
and isotopic analyses indicate a thermal origin for the methane in several
offshore Gulf of Mexico and onshore Alaskan gas-hydrate occurrences.
Gas
and Water Migration Pathways
Other factors controlling the
availability of gas and water are the geologic controls on fluid migration.
As previously shown, gas hydrates contain a substantial volume of gas
and water that must be supplied to a developing gas-hydrate accumulation.
If effective migration pathways are not available, it is unlikely that
a significant volume of gas hydrates would accumulate. Therefore, geologic
parameters such as rock permeability and the nature of faulting must be
evaluated to determine if the required gas and water can be delivered
to the potential hydrate reservoir.
Presence
of Reservoir Rocks and Seals
The study of gas-hydrate samples
recovered during research coring operations in oceanic sediments suggests
that the physical nature of in-situ gas hydrates may be highly variable
(Figure 15, as previously discussed in this paper). Gas hydrates were
observed to be (1) occupying pores of coarse-grained rocks; (2) nodules
disseminated within fine-grained rocks; (3) a solid, filling fractures;
or (4) a massive unit composed mainly of solid gas hydrate with minor
amounts of sediment. This review suggests that porous rock intervals
serve as reservoir rocks in which gas and water can be concentrated in
the amounts necessary for gas-hydrate formation. Therefore, the presence
of reservoir rocks may play a role in gas-hydrate formation, particularly
in well-consolidated rock intervals.
It is also speculated that
the presence of effective reservoir seals or traps may play a role in
gas-hydrate formation. Gas generated at depth moves upward, generally
along tilted permeable carrier beds, until it either seeps at the surface
or meets an impermeable barrier (trap) that stops or impedes its flow.
As migrating gas accumulates below an effective seal, the total gas concentrations
may reach the critical amounts necessary for the formation of gas hydrates.
Thus, impermeable seals can provide a mechanism by which the required
gas can be concentrated within reservoir rocks.
Besides conventional reservoirs
and trapping mechanisms, it is possible for gas hydrate to form its own
reservoir and trap. As gas migrates into the zone of gas-hydrate stability,
it may interact with the available pore water to generate gas hydrate.
With the appropriate volumes of gas and water, the pore space within the
reservoir rock could be completely filled, thus making the rock impermeable
to further hydrocarbon migration. The plugging of gas pipelines and production
tubing by gas hydrates is testimony to the sealing potential of gas hydrates
(Sloan, 1998). It has also been shown that, in marine environments, gas
hydrates can mechanically displace sediments to form their own reservoir.
Thus, the availability of reservoir quality rocks may not always be a
limiting factor.