1) Gas hydrate reservoirs can be characterized using well logs such as resistivity and acoustic logs to determine gas hydrate saturation. More advanced logs like NMR provide insights into pore-scale distribution and reservoir properties. 2) Studies including the Mount Elbert well in Alaska utilized logs like NMR alongside cores and pressure testing to understand gas hydrate occurrence in sediments and obtain properties like porosity, saturation, and permeability. 3) NMR can estimate fluid volumes like free water, clay-bound water, and gas hydrate saturation when combined with density logs, providing a more accurate understanding of gas hydrate reservoirs compared to resistivity alone.

1. SPE 168760 / URTeC 1579782
Gas Hydrate Reservoir Properties
Timothy S. Collett*, U.S. Geological Survey Denver Federal Center, MS-939,
Box 25046, Denver, Colorado 80225, USA; Email: tcollett@usgs.gov
Copyright 2013, Unconventional Resources Technology Conference (URTeC)
This paper was prepared for presentation at the Unconventional Resources Technology Conference held in Denver, Colorado, USA, 12-14 August 2013.
The URTeC Technical Program Committee accepted this presentation on the basis of information contained in an abstract submitted by the author(s). The contents of this paper
have not been reviewed by URTeC and URTeC does not warrant the accuracy, reliability, or timeliness of any information herein. All information is the responsibility of, and, is
subject to corrections by the author(s). Any person or entity that relies on any information obtained from this paper does so at their own risk. The information herein does not
necessarily reflect any position of URTeC. Any reproduction, distribution, or storage of any part of this paper without the written consent of URTeC is prohibited.
Summary
It is generally accepted that the volume of natural gas contained in the world's gas hydrate accumulations greatly
exceeds that of known gas reserves. There is also growing evidence that natural gas can be produced from gas
hydrates with existing conventional production technology. Advancements in nuclear-magnetic-resonance (NMR)
logging and wireline formation testing have allowed for the characterization of gas hydrate reservoirs at the pore
scale. Integrated NMR and formation testing studies from northern Canada and Alaska have yielded valuable
insight into how gas hydrates are physically distributed in sediments and the occurrence and nature of pore fluids
(i.e., free-water along with clay- and capillary-bound water) in gas hydrate-bearing reservoirs. Information on the
distribution of gas hydrate at the pore scale has provided invaluable insight on the mechanisms controlling the
formation and occurrence of gas hydrate in nature along with new data on gas hydrate reservoir properties (i.e.,
porosities and permeabilities) needed to accurately predict gas production characteristics for various gas hydrate
production methods.
Introduction – Gas Hydrate Reservoir Models
In recent years significant progress has been made in addressing key issues controlling the formation and occurrence
of gas hydrate in nature. One of the most important factors that contribute to the formation of gas hydrate is the
physical properties of the host reservoir. The study of gas-hydrate samples indicates that the physical nature of in-
situ gas hydrates is highly variable (reviewed by Sloan and Koh, 2008). Gas hydrates are observed (1) occupying
pores of coarse-grained rocks; (2) nodules disseminated within fine-grained rocks; (3) a solid substance, filling
fractures; or (4) a massive unit composed mainly of solid gas hydrate with minor amounts of sediment. Most gas
hydrate field expeditions, however, have shown that the occurrence of concentrated gas hydrate is mostly controlled
by the presence of fractures and/or coarser grained sediments in which gas hydrate fills fractures or is disseminated
in the pores of sand-rich reservoirs (Collett, 1993; Dallimore and Collett, 2005; Riedel et al., 2006; Collett et al.,
2008a, 2008b; Hutchinson et al., 2008; Park et al., 2008; Yang et al., 2008; Fujii et al., 2008). Torres et al., (2008)
concluded that hydrate grows preferentially in coarse-grained sediments because lower capillary pressures in these
sediments permit the migration of gas and nucleation of hydrate. The growth of gas hydrate in clay-rich sediments,
however, is more poorly understood and appears to be limited to mostly massive occurrences.
Gas Hydrate Field Studies
In recent years, a growing number of deep sea drilling expeditions have been dedicated to locating marine gas
hydrates and understanding the reservoir properties that control their occurrence and potential production
characteristics. The most notable projects have been those of the Ocean Drilling Program (ODP) and the Integrated
Ocean Drilling Program (IODP), including ODP Legs 164 (Paull et al., 1996) and 204 (Tréhu et al., 2004) and IODP
Expedition 311 (Riedel et al., 2006). One of the more important series of national led gas hydrate projects has been
conducted in the offshore of Japan, including the METI Nankai Trough Project in 1999-2000, the METI Toaki‐oki
to Kumano‐nada Project in 2004, and the MH‐21 Nankai Trough Pre‐Production Expedition in 2012 (Fuji et al.,
2008, 2009; Yamamoto et al., 2012). Several more recent industry focused gas hydrate drilling projects such as the

2. URTeC 1579782 2
DOE sponsored Gulf of Mexico Gas Hydrate Joint Industry Project Legs I and II (Ruppel et al., 2008; Collett and
Boswell, 2012) and the India NGHP Expedition 01 (Collett et al., 2008a, 2008b) have also contributed greatly to our
understanding of marine gas hydrates. Recent drilling projects in the offshore of China (Wu et al., 2008) and South
Korea including UBGH1 and UBGH2 (Park, 2008; Lee, 2011) have also made significant contributions to our
understanding of gas hydrates in marine environments and in each case they have featured the acquisition of
extensive downhole well log data sets.
Two of the most studied terrestrial permafrost-associated gas hydrate accumulations are those at the Mallik site in
the Mackenzie River Delta of Canada and the Eileen gas hydrate accumulation on the North Slope of Alaska
(Dallimore and Collett, 2005; Boswell et al., 2011). The Mallik gas hydrate production research site has been the
focus of three geologic and engineering field programs and has yielded the first fully integrated production test of a
natural gas hydrate accumulation. The science program in support of the DOE and BP sponsored Mount Elbert gas
hydrate test well project in northern Alaska generated one of the most comprehensive data sets on an Arctic gas
hydrate accumulation along with critical gas hydrate reservoir engineering data (Boswell et al., 2011). A major
component of both the Mallik and Mount Elbert drilling programs was the deployment of advance downhole
wireline logging technology to further develop and refine the use of well log data to interpret the presence and in-
situ nature of gas hydrate reservoir systems.
Gas Hydrate Reservoir Porosity, Saturation and Permeability Data and Models
The most useable petrophysical data on gas hydrate reservoirs has come from the analysis of well log data from a
relative small number of the dedicated gas hydrate research wells as described above in this report. The most
established and well known use of downhole logs in gas hydrate research are those that provide of electrical
resistivity and acoustic velocity data (both compressional- and shear-wave data) to estimate gas hydrate contents
(i.e., reservoir saturations) in various sediment types and geologic settings. Recent integrated sediment coring and
well log studies have confirmed that electrical resistivity and acoustic velocity data can yield accurate gas hydrate
saturations in sediment grain-supported (isotropic) systems such as sand reservoirs.
One of the more advanced recent downhole wireline logging programs was executed as part of the Mount Elbert Gas
Hydrate Stratigraphic Test Well in northern Alaska in 2007 (Boswell et al., 2011). The Mount Elbert well was
designed as a 22-day program with the planned acquisition of cores, well logs, and downhole reservoir pressure test
data. The gas-hydrate-bearing reservoirs in the Mount Elbert well were drilled using a fit-for-purpose mineral oil-
based drilling fluid. Although this choice added both cost and additional operational complexities, the drilling fluid
could be kept chilled at or below 0°C to mitigate the potential for gas hydrate dissociation and hole destabilization
and thereby preserve core, log, and reservoir pressure test data quality. The well was first continuously cored from
near the bottom of the surface casing to a depth of 2,494 ft using the Reed Hycalog Corion wireline-retrievable
coring system. After coring, the hole was deepened to 3,000 ft, reamed to a diameter of 8 ¾-inches, and surveyed
with a research-level wireline-logging program including neutron-density sediment porosities, nuclear magnetic
resonance, dipole acoustic and electrical resistivity logging, resistivity scanning, borehole electrical imaging, and
advanced geochemistry logging. Caliper data indicate that the hole was almost entirely within several centimeters of
gauge, and virtually fully in gauge within the gas-hydrate-bearing intervals. This outcome is due largely to the use
of oil-based drilling fluid and successful chilling of the drilling fluids with a surface heat exchanger. Following
logging, reservoir pressure testing was conducted with the Schlumberger Modular Formation Dynamic Tester
(MDT) at four open-hole stations in two hydrate-bearing sandstone reservoirs.
Gas hydrates were expected and found in two stratigraphic zones (Figure 1a-b) ― an upper zone (unit D) containing
44 ft of gas-hydrate-bearing reservoir-quality sandstone, and a lower zone (unit C) containing 54 ft of gas-hydrate-
bearing reservoir. Over 504 ft of high quality cores were recovered from the Mount Elbert well between 1,990-
2,494 ft (Boswell et al., 2011). These cores have been the subject of intensive petrophysical examination. The
cored and logged gas hydrate occurrences (unit C 2,132-2,186 ft and unit D 2,016-2,060 ft) exhibit deep electrical
resistivity measurements ranging from about 50 to 100 ohm-m and compressional-wave acoustic velocities (Vp)
ranging from about 3.4 to 4.0 km/sec. In addition, the measured shear-wave acoustic velocities (Vs) of the gas-
hydrate-bearing horizons in the Mount Elbert well ranged from about 1.1 to 1.8 km/sec.
Recent advancements in nuclear-magnetic-resonance (NMR) logging and wireline formation testing has allowed for
the characterization of gas hydrate at the pore scale. Integrated NMR and formation testing studies in the Mount

3. URTeC 1579782 3
Elbert well have yielded valuable insight into how gas hydrates are physically distributed in sediments and the
occurrence and nature of pore fluids (i.e., free-water along with clay and capillary-bound water). This study has also
provided critical data on gas hydrate reservoir properties (i.e., porosities and permeabilities) needed to accurately
predict gas production rates for various gas hydrate production schemes.
Figure 1 a-b: Summary of the wireline logs from the BPXA-DOE-USGS Mount Elbert Gas Hydrate Stratigraphic Test
Well on the Alaska North Slope (modified from Collett et al., 2011). (a) Wireline log data from the sub-permafrost section
of the well, also shown is the gas-hydrate-bearing portions of the unit C and D sands. (b) Well log derived gas hydrate
saturations, sediment porosities, and reservoir permeabilities within the gas-hydrate-bearing portions of the unit C and D
sands.

4. URTeC 1579782 4
In recent years there have been significant developments in the field of nuclear magnetic resonance well logging
(reviewed by Kleinberg et al., 2005). Similar to neutron porosity devices, NMR tools primarily respond to the
presence of hydrogen molecules in the rock formation. There are numerous studies in which laboratory apparatuses
have been used to characterize the nuclear magnetic properties of gas hydrates. Collett et al., (2005) showed that the
nuclear magnetic resonance transverse magnetization relaxation time (T2) of the water molecules in the Structure-I
gas hydrate is about 0.01 milliseconds which is very similar to the relaxation times of other solids such as the rock
matrix. Transverse magnetization relaxation times (T2) on the order of 0.01 milliseconds are sufficiently short
enough to be lost in the "dead time" (below the detectable limit of the tool) of standard nuclear magnetic resonance
borehole instruments. Gas hydrates, therefore, cannot be directly detected with today’s downhole nuclear magnetic
resonance technology. It has been shown, however, that due to the short transverse magnetization relaxation times
(T2) of the water molecules in the clathrate structure, gas hydrates would not be "seen" by the nuclear magnetic
resonance tool and the in-situ gas hydrate would be assumed to be part of the solid matrix. Thus, the nuclear-
magnetic-resonance-calculated total porosity estimate in a gas-hydrate-bearing sediment would be apparently lower
than the actual porosity. With an independent source of accurate in-situ total porosities, such as density log
measurements, it would be possible to accurately estimate gas-hydrate saturations by comparing the apparent
nuclear-magnetic-resonance-derived porosities with the actual total porosities.
A convenient method for computing gas hydrate saturations (Sh) has been developed which uses porosities estimated
from density and NMR logs (modified from Kleinberg et al., 2005). The NMR derived porosity NMR is a
measurement of the pore space occupied by only water (free-water, capillary- and clay bound water) not included in
the gas hydrate structure and is given by the following equation:
)1( hNMR S  (1)
where
h
NMRhD






1
(2)

 NMR
hS

 (3)
and
wma
hw
h





 (4)
wma
bma
D





 (5)
Note that D is the density porosity derived assuming a two-component system (matrix and water; Equation 1) and
NMR is the same as the water-filled porosity that is defined as  )1( hw S . The porosity given in Equation 2
is total porosity, which is the pore space occupied by water and gas hydrate. ‘‘Total porosity’’ and porosity are used
interchangeably in this report.
The gas hydrate saturations estimated from the NMR-density porosity method does not depend on the reservoir
model or parameters, so the accuracy of the estimation depends only on the accuracy of NMR-density porosity log
measurements. Therefore, it is assumed that gas hydrate saturations estimated from the NMR-density porosity
method are the most accurate in-situ gas hydrate saturations and the accuracy of other methods can be evaluated
using the NMR-density porosity derived saturations as reference saturations. The NMR-density porosity derived gas

5. URTeC 1579782 5
hydrate saturation log as calculated for the Alaska Mount Elbert well have been plotted in Figure 2 for comparison
with the resistivity derived gas hydrate saturation log.
Figure 2: Gas hydrate saturations estimated from the electrical resistivity and NMR-density
porosity logs in the Alaska Mount Elbert well (modified from Lee and Collett, 2011).
NMR logs have also been used to gain valuable insight to other gas hydrate reservoir properties. As discussed
above, the NMR-recorded transverse-magnetization-relaxation time (T2) of a formation depends on the relaxation
characteristics of the hydrogen-bearing substances in the rock formation. For example, T2 for hydrogen nuclei in
solids is very short, whereas T2 for hydrogen nuclei in fluids can vary from tens to hundreds of milliseconds,
depending on fluid viscosities and interactions with nearby surfaces. In standard NMR borehole logging, the T2
relaxation signal is divided into a series of time windows, with each representing a portion of the T2 signal that can
be attributed to the various ‘types’ of water within a porous rock unit, providing accurate volumetric estimates of the
amount of clay-bound water, capillary-bound water, and free-water in gas-hydrate-bearing reservoirs. NMR log
data from the Mallik 2L-38 well in Canada (Dallimore and Collett, 2005) and the Alaska Mount Elbert well (Collett
et al., 2011) have shown relatively high volumes of free-water content (ranging from as high as 10 to 15 percent) in
reservoirs with high gas hydrate saturations.
Another primary goal of NMR logging is to measure the permeability of rocks to the flow of various formation
fluids. Two empirical relations have been developed to use NMR log data to predict in-situ fluid permeabilities: the
SDR and Timur/Coates methods (reviewed by Collett et al., 2011). The NMR log data from the Alaska Mount
Elbert well shows that the permeabilities of the non-hydrate-bearing sand reservoirs (in the absence of gas hydrate)

6. URTeC 1579782 6
are very high, in the multiple Darcy range (Collett et al., 2011). The permeabilities in the hydrate-bearing sand
reservoirs, however, are very low on the order of 0.01 to 0.10 mD.
The Alaska Mount Elbert gas hydrate stratigraphic test well project also included the acquisition of pressure
transient data from four short-duration open-hole, dual-packer pressure-drawdown tests using Schlumberger’s
wireline MDT (Boswell et al., 2008; Anderson et al., 2008). These tests were conducted in open-hole, and were
designed to build upon the knowledge gained from cased-hole MDT tests conducted during the Mallik 2002 testing
program. A unique aspect of the Mount Elbert program was that these experiments were conducted in the open
hole, removing many complexities related to the nature and effect of casing perforations. In comparison to the
Mallik 2002 MDT tests, the individual Mount Elbert tests were of much longer duration, with the test lengths
ranging from 6 to nearly 13 hours.
Figure 3: Downhole pressure data from MDT test C2 at ~656 m (2,151 ft) in the Mount Elbert gas hydrate stratigraphic test
well. Plot shows three pressure drawdown-recovery sequences (modified from Anderson et al., 2008).
Four one-meter-thick zones were tested in the Mount Elbert well: two in Unit C (tests C1 and C2) and two in Unit D
(tests D1 and D2) (Figure 1 a-b). Each test consisted of multiple stages of varying duration, with each stage
consisting of a period of fluid withdrawal (thereby reducing formation pressure) followed by a period where the
pump is shutoff and the subsequent pressure build-up is monitored (Figure 3). Gas and water samples were
collected during selected flow periods and a fluid analyzer on the MDT tool enabled the identification (but not
volumetric measurement) of gas and water as it entered the tool. Also a small programmable sensor was attached to
the outside of the tool in order to monitor temperature changes during each test.
To investigate the petrophysical properties of the hydrate-bearing reservoirs, each of the four tests within the Mount
Elbert MDT program began with a “pre-flow test” in which pressure was reduced enough to mobilize unbound
formation water but not enough to induce gas hydrate dissociation. To provide insight into gas hydrate response to
small-scale pressure transients, the pre-flow tests were followed by numerous test stages in which the pressure
reduction was great enough to induce gas hydrate dissociation. The MDT log data from the Mount Elbert well also
confirmed the presence of a mobile pore-water phase even in the most highly gas hydrate-saturated intervals. In the
Mount Elbert unit D sand, the mobile water phase was determined to be about 8 to 10% of total pore volume, and in
the unit C sand, it appears to range upward to ~15% (Anderson et al., 2008).

7. URTeC 1579782 7
The MDT test data from the early pre-flow stage that targeted fluid withdrawal without gas hydrate dissociation
produced pressure responses that are typical of low-permeability porous media much like the Mallik 2002 MDT
tests. Analysis of these pre-flow tests in a variety of advanced reservoir simulators (Anderson et al., 2008) has
yielded reservoir permeabilities, in the presence of a gas hydrate phase, of 0.12 to 0.17 mD.
The MDT and CMR log data from the Mount Elbert unit C and D hydrate-bearing sands indicates the presence of
mobile water, even in the most highly gas-hydrate saturated intervals. From the NMR log in unit D, the mobile
water may be 8 to 10% of the total pore volume. In the case of unit C it appears the mobile water phase may exceed
15% of measured pore volume. The successful depressurization of the reservoir by fluid withdrawal during the
MDT program confirms the NMR observation. Analysis of MDT reservoir pressure tests in a variety of advanced
reservoir simulators (reviewed by Boswell et al., 2011) has enabled an estimate of 0.12 to 0.17 mD for the in-situ
effective permeability of the reservoir in the presence of the gas hydrate phase, which compares favorably to NMR
log derived reservoir permeabilities.
Conclusions
As shown in this review, downhole log data can be used to obtain highly accurate reservoir porosity, permeability,
and gas hydrate saturation data within a wide range of gas hydrate reservoir conditions. One of the most important
developments has been the use of nuclear magnetic resonance well log to obtain gas hydrate saturation and other
important reservoir information. In closing, downhole acquired well log data have made significant contributions to
our understanding of the formation and occurrence of gas hydrates in nature and will continue to play a key role in
advancing our understanding of this emerging energy resource.
Acknowledgements
This work was funded by the U.S. Department of Energy, U.S. Bureau of Land Management, and the Energy
Resources Program of the U.S. Geological Survey. Any use of trade, product, or firm names is for descriptive
purposes only and does not imply endorsement by the U.S. Government.
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