DOWNHOLE WELL LOG CHARACTERIZATION OF
GAS HYDRATES IN NATURE – A REVIEW
Timothy S. Collett and Myung W. Lee
U.S. Geological Survey, Denver Federal Center
MS-939, Box 25046, Denver, Colorado, 80225
UNITED STATES OF AMERICA
ABSTRACT
In the last 25 years we have seen significant advancements in the use of downhole well logging
tools to acquire detailed information on the occurrence of gas hydrate in nature. From an early
start of using wireline electrical resistivity and acoustic logs to identify gas hydrate occurrences in
wells to today where wireline and advanced logging-while-drilling tools are routinely used to
examine the petrophysical nature of gas hydrate reservoirs and the distribution and concentration
of gas hydrates within various complex reservoir systems. The most established application of
downhole log data in gas hydrate research is the use of electrical resistivity and acoustic velocity
data to make estimates of gas hydrate concentrations. 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 systems such as sand reservoirs, but more
advanced log analysis models are required to characterize gas hydrate in fractured reservoir
systems. New downhole logging tools designed to make directionally oriented acoustic and
propagation resistivity log measurements have provided the data needed to analyze the acoustic
and electrical anisotropic properties of both highly inter-bedded and fracture dominated gas
hydrate reservoirs. Integrated nuclear magnetic resonance logging and formation testing have
yielded valuable insight into how gas hydrates are physically distributed in sediments and the
occurrence and nature of pore fluids in gas-hydrate-bearing reservoirs. Information on the
distribution of gas hydrate at the pore scale have provided invaluable information on the
mechanisms controlling the formation and occurrence of gas hydrate in nature along with data on
gas hydrate reservoir properties (i.e., permeabilities) needed to accurately predict gas production
rates for various gas hydrate production schemes. The primary objective of this report is to
review the historical contributions that the analysis of downhole acquired well log data have
made to our understanding of the formation and occurrence of gas hydrates and nature.
Keywords: gas hydrate, petrophysics, well logging, saturation, porosity
Corresponding author: Phone: +1.303.236.5731, E-mail: [email protected]
INTRODUCTION
As interest in gas hydrate as a potential energy
resource continues to grow the need for accurate
assessments of the amount gas stored in gas
hydrate at the accumulation or basin scale is
becoming more important. The amount of gas that
might be stored in a gas hydrate accumulation is
dependent on a number of reservoir parameters,
including the areal extent of the gas-hydrate-
bearing reservoir, reservoir thickness, reservoir
porosity, and the degree of gas hydrate saturation
[1]. Two of the most important reservoir
parameters to determine are porosity and the
degree of gas-hydrate saturation. Downhole well
logs, both wireline conveyed and logging-while-
drilling tools, often serve as a source of high
quality porosity and gas hydrate saturation data.
Proceedings of the 7th International Conference on Gas Hydrates (ICGH 2011),
Edinburgh, Scotland, United Kingdom, July 17-21, 2011.
Until recently most of the existing gas hydrate
well-log evaluation techniques have been develop
by the extrapolation of uncalibrated petroleum
industry log evaluation procedures [1]. The
relatively recent emergence of numerous national
gas hydrate research programs, however, has led to
execution of a long list of marine and onshore
arctic gas hydrate research drilling and down hole
logging programs [reviewed by 2]. Within these
recent drilling projects, downhole logs have
provided robust information about complex gas
hydrate reservoir systems containing pore and
fracture filling gas hydrate, sediment grains of
various sizes and compositions, water at various
reservoir states, and free gas occurrence [3, 4, 5, 6,
7, 8, 9, 10, 11, 12, 13, 14].
This report reviews our existing understanding of
the reservoir properties of known gas hydrate
occurrences and provides a comprehensive
assessment of the existing state-of-the-art
quantitative gas hydrate log analysis techniques.
WELL LOG DATA ACQUISTION AND
EXAMPLE DATA SETS
In recent years, a growing number of deep sea
drilling expeditions have been dedicated to
locating marine gas hydrates and understanding
the geologic controls on their occurrence. The
most notable projects have been those of the
Ocean Drilling Program (ODP) and the Integrated
Ocean Drilling Program (IODP), including ODP
Legs 164 [15] and 204 [16] and IODP Expedition
311 [17]. Several more recent industry focused
gas hydrate drilling projects such as the DOE
sponsored Gulf of Mexico Gas Hydrate Joint
Industry Project Legs I and II [18, 19] and the
India NGHP Expedition 01 [9] have contributed to
our understanding of marine gas hydrates. Recent
drilling projects in the offshore of China [20] and
South Korea including UBGH1 and UBGH2 [21,
22] 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 [23, 24]. 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 [24].
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.
In most of the completed gas hydrate downhole
logging projects, the log data are acquired from
sensors that are either lowered into the hole on a
wireline (ie., wireline logging surveys) or are built
directly in the drill-pipe and drill-bit assemblage
with the formation measurements being made as
the hole is drilled (ie., logging while drilling
surveys), both of these logging approaches are
further reviewed in the following section of this
report.
Wireline logging
In downhole wireline logging, the logging tools
are joined together in “tool strings”, so that several
measurements can be made during each logging
run. The tool strings are lowered to the bottom of
the borehole on a wireline cable, and data are
recorded as the tool string is pulled back up the
hole.
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 [24]. 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 [24]. These cores have been the
subject of intensive petrophysical examination, the
results of which have been used in the well log
displays associated with this report to validate and
calibrate the acquired downhole log data. 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. Both units
displayed gas hydrate saturations that varied with
reservoir quality, with typical values between
about 50% and 78% of the pore volume. The log
derived gas hydrate saturations in the Mount
Elbert well will be further reviewed later in this
report. Core-derived estimates of intrinsic (in the
absence of gas hydrate) permeabilities are very
high, in the multiple Darcy range [24]. Porosities
are also high, averaging 38% in unit D and
reaching 40% within unit C. The CMR log
indicates the presence of mobile water, even in the
most highly gas-hydrate saturated intervals. In
unit D, mobile water may be 8 to 10% of 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 this observation. Analysis of
MDT reservoir pressure tests in a variety of
advanced reservoir simulators [reviewed by 24]
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 the CMR log derived reservoir
permeabilities.
Logging while drilling
Logging while drilling (LWD) tools are
instrumented drill collars in the bottom-hole
assembly (BHA), near the bit, which measure in-
situ formation properties. Measurement while
drilling (MWD) tools, also located in the BHA
with the LWD sensors, measure downhole drilling
parameters and wellbore direction. The MWD
tool also transmits limited LWD data to the
surface to be monitored in real-time. Complete
LWD data are recorded into downhole computer
memory and retrieved when the tools are brought
to the surface. LWD measurements are made
shortly after the formation is drilled and before the
adverse effects of continued drilling or coring
operations. Erosion of the borehole wall due to
prolonged circulation and drilling fluid invasion
into the formation are reduced relative to wireline
logging because of the shorter time elapsed
between drilling and taking measurements. In
most of the completed gas hydrate drilling
projects, the LWD operations are conducted in
advance of coring, often during a dedicated LWD
leg. These pre-coring logging operations are
critical to the development of the detailed, site-
specific coring, core sampling and pressure core
deployment plans. LWD data also provides real-
time borehole monitoring data during drilling,
which can be used to assess potential drilling
problems associated with the presence of gas
hydrate. Results of previous gas hydrate drilling
programs have shown that drilling hazards
associated with gas hydrate bearing sections can
be managed through careful control of drilling
parameters [9]. The primary measurement used
for gas monitoring has been the annular pressure
while drilling measurement, or APWD [17].
Figure 1a-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.
Figure 2 Logging while drilling logs from
the Gulf of Mexico JIP Leg II Hole GC995-
H (modified from Guerin et al., 2009).
The primary objective of the Gulf of Mexico Gas
Hydrate Joint Industry Project Leg II (GOM JIP
Leg II) was the collection of a comprehensive
suite of LWD data within gas-hydrate-bearing
sand reservoirs [19]. Six LWD and MWD tools,
provided by Schlumberger Drilling and
Measurements, were deployed in each hole. The
LWD tools used during the JIP expedition were
the MP3 (multipole acoustic - recently
commercialized under the name SonicScope),
geoVISION (electrical imaging), EcoScope
(propagation resistivity, density and neutron
porosity), TeleScope (MWD), PeriScope
(directional propagation resistivity), and
sonicVISION (monopole acoustic). Because of its
slimmer 4 ¾ inch collar, the MP3 was located
behind the 6 ¾ inch bit and below an 8 ½ inch
hole-opening reamer, above which were the rest of
the 6 ¾ inch LWD collars. For additional
information about the measurements recorded by
each tool on the LWD bottom hole assembly
(BHA) see the review by Boswell et al., [19].
Ultimately during GOM JIP Leg II three sites were
occupied with seven LWD holes being drilled, a
total of 15,380 ft formation were drilled and
logged during this research leg. Penetration
depths varied from 1,116 to 3,586 feet below
seafloor (ftbsf). During the GOM JIP Leg II there
were 4.8 days spent in transit or mobilizing
equipment, another 15.1 days were spent on-site
conducting drilling operations. To provide the
highest quality data, the JIP had planned to
eliminate the use of heavy drilling fluids and
exclusively use sea-water with periodic gel sweeps
as needed. This plan was altered in the field to
include regular drill mud use upon the observation
of inefficient cuttings removal during the drilling
of the initial well (WR313-G) that resulted in
necessary back-reaming and other drilling
measures that eroded the hole, compromising the
quality of some of the LWD data. Throughout the
remainder of Leg II, mud circulation was
implemented prior to the onset of pipe-sticking
issues (commonly at ~1,700 to 1,900 ftbsf),
resulting in substantially improved LWD quality.
Careful control of drilling fluid temperatures
mitigated risks related to gas hydrate dissociation
during drilling; resulting in incident-free drilling
through many gas-hydrate rich sections. In fact,
the caliper data clearly indicate that the most
stable portions of the wells drilled during JIP Leg
II were those in which substantial volumes of gas
hydrate were present, providing significant
additional mechanical strength to the otherwise
highly-unconsolidated sediments.
For demonstration purposes some of the log data
collected from the GC955-H well have been
displayed in Figure 2. The GC955-H well, at a
water depth of 6,670 ft, was the second location
drilled in Green Canyon Block 955 during the
GOM JIP Leg II. GC955-H was drilled without
any significant problems and without any special
measures other than the standard use of drilling
mud. GC955-H penetrated a thick gas-hydrate-
filled fracture section within the depth interval of
532-952 ftbsf and at a depth of 1,256 ftbsf the well
encountered a thick gas-hydrate-bearing sand
section; thus representing the complete range of
gas hydrate reservoir conditions encountered
during the GOM JIP Leg II. On the resistivity
images, gas-hydrate-filled fractures in the depth
interval of 532-952 ftbsf appear as resistive
sinusoids. Intervals containing high angle gas
hydrate-filled fractures can be identified from the
propagation resistivity measurements where the
P40H and/or the A40H curves significantly exceed
the P16H and A16H curves because of the
electrical anisotropy due to the resistive fracture
planes (Figure 2). As drilling proceeded below a
depth of 1,256 ftbsf, the gamma-ray response of
the sediments steadily decreased, indicative of
increasing sand content. Overall, a sand-rich unit
roughly 325-ft thick was encountered. High-
resolution resistivity images showed the unit to
consist of interbedded sands and shales, with sands
commonly 1-2 ft in thickness, with maximum
thickness of 4 ft. These sands are inter-layered
with shales that are typically 0.5 to 1 foot thick.
The upper 75 ft of this interval has low and
downward decreasing resistivity and is therefore
interpreted to be water-saturated. At 1,357 ftbsf,
resistivity and acoustic velocity increased sharply,
indicating the top of a thick gas-hydrate-bearing
sand interval. Through a depth of 1,476 ftbsf,
three gas-hydrate-bearing zones of 88 ft, 13 ft, and
3 ft thick were logged. Unexpectedly, these zones
are separated by two zones of hydrate-free, water-
bearing sands units. The average Archie derived
gas hydrate saturations within the drilled sand
sections in the GC955-H well is ~65%, while the
gas hydrate was determined to occupy only about
5-8% of the void space created by the fractures in
the upper part of the well [25].
WELL LOG DATA ACQUISTION AND
EXAMPLE DATA SETS
The most commonly used logs to identify and
characterize gas-hydrate-bearing reservoirs are
borehole images, porosity, resistivity,
electromagnetic, acoustic, and nuclear magnetic
resonance. In this section of the report, a
comprehensive set of quantitative gas hydrate well
log evaluation techniques have been described and
used in a series of example well log studies.
Borehole imaging logs
Borehole imaging has become a standard feature
of most wireline and LWD gas hydrate logging
programs. For the most part high-resolution
wireline formation micro-scanners (FMS) or
micro-imagers (FMI) along with LWD resistivity-
at-bit (RAB) electrical images have been used for
the identification of thin beds, veins, and fractures
in gas-hydrate-bearing sediments. In the case of
the Alaska Mount Elbert well an oil-based
microimager (OBMI) was deployed in order to
deal with the oil based mud used to drill this hole.
The FMS produces high-resolution images of
borehole wall microresistivity that can be used for
detailed sedimentologic or structural
interpretation. This tool has four orthogonally
oriented pads, each with 16 button electrodes (5
mm diameter) that are pressed against the borehole
wall. Approximately 30 percent of a borehole
with a diameter of 25 cm is imaged during a single
pass. The vertical resolution of FMS images is ~5
mm, allowing features such as burrows, thin beds,
fractures, veins, and vesicles to be imaged. The
resistivity measurements are converted to color or
grayscale images for display and the images are
oriented to magnetic north. This allows the dip
and strike of geological features intersecting the
hole to be measured from processed FMS images.
The LWD GeoVISION resistivity, or GVR tool
provides resistivity measurements of the formation
and electrical images of the borehole wall that are
similar to the wire-line FMS but with complete
coverage of the borehole walls and lower vertical
and horizontal resolution.
Shown in Figure 3a-b are some of the LWD
borehole images collected by the EcoScope and
geoVISON (GVR) tools in the GOM JIP Leg II
GC955-H well. The GVR produces shallow,
medium and deep depth of investigation resistivity
images of the borehole along with gamma ray
images. The EcoScope tool also produces images
of density and hole radius (computed on the basis
of the density correction, which is a function of
borehole standoff), as well as gamma ray and
photoelectric factor. The unwrapped images in
Figure 3a-b are about 70 cm wide (for an 8.75 inch
diameter borehole) and the vertical scale in these
figures is highly compressed relative to the
horizontal. Gas hydrate-bearing sediments exhibit
high resistivity within intervals of uniform or low
bulk density. By comparison, layers with high
resistivities and high densities are likely to be low
porosity, compacted, or carbonate-rich sediments.
In Hole GC955-H, one of the most prominent
features is the high-resistivity gas-hydrate-bearing
interval between ~1,350 and 1,450 ftbsf.
In addition, Hole GC955-H includes a thick
interval of apparent gas-hydrate-filled fractures in
clay sediments between 630 and 960 ftbsf (Figures
2 and 3a-b), and one smaller interval between
1,115 and 1,142 ftbsf. On the resistivity images,
gas-hydrate-filled fractures appear as resistive
sinusoids. Near the peaks and troughs of the
resistive sinusoids, bright resistive halos can
appear due to the current avoiding the path
containing gas hydrate, often adjacent to dark
conductive partial sinusoids where the current path
is concentrated [26].
Gamma-gamma density logs
In conventional formation analysis and in gas-
hydrate-bearing reservoirs, density logs are
primarily used to assess in-situ sediment
porosities. The typical density of a Structure-I
methane hydrate is about 0.9 g/cm3 [reviewed by
27]. In conventional formation density logging,
porosities are derived from this standard relation:
wma
bma
D
(1)
Where ma is the known matrix density (g/cm3),
w is the fluid (water) density (g/cm3), and b is
the log-measured formation bulk-density (g/cm3).
To calculate porosities within a gas-hydrate-
bearing rock unit a modified density equation has
been developed for a three-component system
(water, hydrate, matrix) [reviewed by 1]:
hhhwmab CC )1()1( (2)
Figure 3a-b (a) Logging while drilling borehole
image logs from the Gulf of Mexico JIP Leg II
Hole GC995-H (modified from Guerin et al.,
2009). (b) Downhole logs and logging while
drilling borehole resistivity image from 626 to 713
ftbsf in the Gulf of Mexico JIP Leg II Hole
GC995-H (modified from Guerin et al., 2009).
Equation 2 documents that gas hydrates can cause
a small but measurable effect on density-derived
porosities where hC is gas hydrate saturation. If
the density of the hydrocarbon (gas hydrate) is
known, it is possible to obtain “gas hydrate”
corrected density-derived porosities with Equation
2.
Neutron porosity logs
Neutron logs are mostly used to delineate porous
formations and determine their porosity. Neutron
porosity logs primarily measure the amount of
hydrogen within the pore-space of the rock
sequence, which can be related to the amount of
water and hydrocarbons, including gas hydrates,
that are present. Collett et al., [27] developed a
neutron porosity log gas hydrate correction factor
based on assessing the hydrogen index (ie.,
hydrogen content) of a Structure-I methane
hydrate and other potential pore-filling
constituents. Hydrogen indexes are often used to
compare hydrogen concentrations in different
reservoir constituents. The hydrogen index (HI) of
a substance is defined as the ratio of the
concentration of hydrogen atoms per cubic
centimeter in the substance, to that of pure water at
24°C (6.686x1022
hydrogen atoms/cm3). Pure
water therefore has a HI of 1.0. Since a Structure-
I methane hydrate contains 7.084x1022
hydrogen
atoms/cm3, the HI of Structure-I methane hydrate
is 1.059, which is near the HI of pure water. Since
Structure-I methane hydrate and pure water have
similar hydrogen concentrations and HI values it
can be generally assumed that neutron porosity
logs, which are calibrated to pure water, are not
significantly affected by the presence of gas
hydrates. It is possible, however, to further
quantify the effect of gas hydrates on neutron
porosity logs. The following equation can be used
to determine the effect of hydrocarbons on
measured neutron porosities:
)( wwhhN SHICHI (3)
Equation 3 documents that Structure-I methane
hydrate has relatively little effect on neutron
porosity measurements.
Resistivity logs
The relation between rock and pore-fluid
resistivity has been studied in numerous laboratory
and field experiments. From these studies,
relations among porosity, pore-fluid resistivity,
and rock resistivity have been found. Among
these findings is the empirical relation established
by Archie [28], which is used to estimate water
saturations in gas-oil-water-matrix systems. Gas
hydrate which also acts as an electrical insulator,
much like oil or gas, can be detected with
resistivity tools and the derived resistivity
measurement can also be used to estimate gas
hydrate saturations. Collett and Ladd [29], Lee
and Collett [6], Malinverno et al., [13], and Lee
and Collett [30] discuss estimation of gas hydrate
saturations from resistivity logs.
The electrical resistivity of water-saturated
sediments (Ro) can be expressed using the Archie
equation [28] in the following way:
m
w
o
aRR
(4)
where Ro is the formation resistivity of water-
saturated sediment, Rw is the resistivity of the pore
water, a and m are Archie constants, and is the
porosity. Archie constants a and m can be derived
empirically. The values of the a and m Archie
constants depend on the interaction between the
host sediments and gas hydrate in the porous
medium. Equation 4 indicates that a plot of log
relative to log Ro is linear and the slope is given by
m if Rw is constant throughout the interval being
analyzed or if the formation factor (FF), which is
defined as FF = Ro/Rw, is used.
Recently, Sava and Hardage [31] have applied a
different approach to selecting Archie a and m
constants, which may be more appropriate for
near-surface marine environments in which the
sediments are characterized as “highly
unconsolidated, high porosity, and in a near-
suspension-regime”. This technique, originally
proposed by Hashin and Shtrikman [32] was
developed to set the lower bound on the electrical
resistivity for composite materials. Sava and
Hardage [31] showed that for unconsolidated
sediments we should expect significantly lower
values for the Archie cementation exponent m than
we do for deeper consolidated sediments. For the
most part, however, the Archie cementation
exponents (m) as proposed Sava and Hardage [31]
for marine sediments are similar to those
calculated by Archie versus Ro (Pickett cross-
plot) method as described above [12, 13].
The water saturation (Sw) in the formation from the
resistivity log for sediments having hydrocarbons
is given by Archie (1942) as:
n
t
m
ww
R
RaS /1)(
(5)
where n is an empirically derived parameter (often
close to 2) and Rt is the formation resistivity with
gas hydrate or other hydrocarbons. The parameter
n, which depends on the reservoir lithology, has
been shown to vary between 1.715
(unconsolidated sediment) and 2.1661 (sandstone),
and is typically 1.9386 [reviewed by Collett, 1].
The resistivity of the pore water (Rw) can also be
calculated using Arp‟s formula, if the salinity and
temperature of the formation water are known
[reviewed by Collett, 1].
Lee and Collett [30] completed a detailed analysis
of the well log data from the Mount Elbert well,
which also provides us with a good example data
set for this report to demonstrate various well log
derived gas hydrate saturation calculation
methods. Figure 4 shows the calculated Rw from
the core derived pore water salinities and
equilibrated borehole temperature surveys along
with measured formation resistivity (Rt) for the
Mount Elbert well. Note that the average Rw for
most of the section between 2,000 and 2,500 ft is
about 2 ohm-m. For comparison, Rw at the Mallik
5L-58 well, in western Canada, is about 0.45 ohm-
m [33] and at Keathley Canyon, Gulf of Mexico, it
is about 0.2 ohm-m [11]. The zones with elevated
Rw in Figure 4 correspond to the hydrate-bearing
portions of units C and D in the Elbert well and
these anomalous values were caused by the
freshening of the pore water from the dissociation
of gas hydrate in the recovered core samples.
Consequently, the calculated resistivity greater
than about 2 ohm-m in Figure 4 does not represent
in-situ resistivity of the pore water. The Pickett
cross plot approach, which relates formation factor
(FF) to formation resistivity (Rt), was used to
estimate the a and m Archie parameters. Figure 5
shows gas hydrate saturations estimated from the
resistivity log in the Mount Elbert well using a =
1.7, m = 1.0 and with n = 2, with gas hydrate
saturations in the unit C and D sands averaging
between 50 and 70 percent.
Lee and Collett [30] extended their Archie analysis
to consider the effects of clay, within the sediment
matrix, on the resistivity derived gas hydrate
saturations. The effect of clay on the formation
resistivity can be corrected for by using various
“shaly-sand” correction methods. Lee and Collett
[30, 34] proposed a method in which the Archie
parameters a and m are made a function of clay
content of the sediments. The essence of this
method is that the estimates of a and m reflect the
contribution of clay on the sediment resistivity in
such a way that as the clay content increases, a
increases and m decreases. See Lee and Collett
[30, 34] for a detailed discussion on “shaly-sand”
corrections for gas hydrate saturation calculations.
Electromagnetic logs
The fundamental law governing electromagnetic
wave propagation in a media is best described by
Maxwell‟s equations. When the media can be
treated as homogeneous and isotropic at a
macroscopic scale, the electromagnetic properties
can be quantitatively characterized by the
dielectric constant, magnetic permeability, and
conductivity, which are dependent on the
frequency of the propagating wave and the
formation temperature and pressure. In intervals
containing gas hydrate, electromagnetic waves
propagate like acoustic waves, with faster wave
speeds or reduced propagation times relative to
water-bearing sediments [7]; thus, downhole tools
that measure the propagation times of
electromagnetic waves can be used to interpret the
presence of gas hydrate and to estimate gas
hydrate saturations. The electromagnetic-derived
gas hydrate saturations compare favorably with
those interpreted from electrical resistivity and
acoustic logs [7]; but in comparison the wireline
dielectric tools yield a much higher resolution log.
Acoustic logs
Most modern acoustic transit-time logs measure
the propagation of elastic compressional- and
shear-waves through a medium. It has also
become a common practice to use acoustic transit-
time well logs to estimate the amount of gas
hydrate within a drilled sedimentary unit. Since
Lee et al., [35], acoustic modeling of gas hydrate
accumulations has followed two general paths
Figure 4 Plot of log data from the Mount Elbert
well showing measured electrical resistivity with
shale (clay) volume calculated from gamma ray
log, resistivity of pore water (Rw), and baseline
resistivity (Ro) calculated from porosity and Rw
(modified from Lee and Collett, 2011).
Figure 5 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).
Figure 6a Gas hydrate saturations estimated from
the compressional-wave acoustic and NMR-
density porosity logs in the Alaska Mount Elbert
well using the three-phase Biot-type model
(modified from Lee and Collett, 2011).
Figure 6b Gas hydrate saturations estimated from
the compressional- and shear-wave acoustic logs
in the Alaska Mount Elbert well using the three-
phase Biot-type model (modified from Lee and
Collett, 2011).
dealing with either the development of empirical
acoustic relations or the application of multiphase
wave scattering theory, grain contact models, or
effective medium models to directly calculate gas-
hydrate concentrations for various geologic
conditions. Lee et al., [35] generally pursued the
development of a series of empirical acoustic
equations that appear to accurately predict the
acoustic velocity of gas-hydrate-bearing
sediments. Lee et al., [35] also reintroduced and
applied the multiphase wave scattering theory
developed by Kuster and Toksöz [36], to assess
the acoustic properties of gas-hydrate-bearing
sediments. An alternative gas hydrate acoustic
model has been proposed by Dvorkin and Nur
[37], which is based on estimating acoustic
properties of cemented gas-hydrate-bearing
sediments from grain contact theory. But probably
the two most widely cited acoustic models for gas-
hydrate-bearing sediments include the effective
medium theory [38] and the three-phase Biot-Type
equation [10, 30].
Dvorkin and Nur [37] and Helgerud et al., [38]
have proposed and examined several
"micromechanical" models that were designed to
represent the range of gas hydrate occurrence at
the pore-scale. Most of these models suggest that
gas hydrate either fills sediment pores or cements
grain contacts, increasing the stiffness of the
sediment. Acoustic log data from a well drilled in
the Nankai Trough, Japan indicate that gas hydrate
likely occupies the sediment pores and acts as a
load-bearing component of the sediment frame [8].
Similar results were found with the well log data
from the Canadian Mallik 2L-38 test well [5] and
the Alaska Mount Elbert well [30].
In the following example log analysis, the three-
phase Biot-Type equation (TPE) [10, 30] has been
used to determine gas hydrate saturations from the
well log data and cores obtained from the Alaska
Mount Elbert Gas Hydrate Stratigraphic Test Well.
If we assume that gas hydrate acts as a load-
bearing component of the sediments, the
simplified TPE [10] can be used to model the
acoustics velocities of gas-hydrate-bearing
sediments (GHBS). The compressional-wave
velocity (Vp) and the shear-wave velocity (Vs) of
the GHBS can be calculated from the following:
b
p
kV
3/4 and
b
sV
(6)
where k and μ are the bulk and shear modulus of
the GHBS, and ρb is the bulk density of the GHBS
as given by Equation 2.
The bulk and shear moduli of the GHBS using the
simplified TPE is given by Lee [10]:
avppma KKk 2)1( (7)
)1( sma (8)
with
h
h
w
w
ma
p
av KKKK
)(1 (9)
)1(
)1(
as
as
p
(10)
)1(
)1(
s (11)
where α is the consolidation parameter [39],
1
21, hh C , and hwas .
Lee [10] recommended ε = 0.12 for modeling
velocities of GHBS. Ignoring the attenuation, the
velocities calculated using the simplified TPE and
the original TPE at low frequency such as at
logging frequency are virtually identical, but the
simplified TPE is computationally easier to use.
Kma, Kw, and Kh in Equations (7-9) are the bulk
modulus of the grain matrix, water, and gas
hydrate, respectively, and μma is the shear modulus
of the grains. Note that Kma and μma include the
bulk and shear moduli of gas hydrate and are
computed using Hill‟s [40] average formula as
shown in Helgerud et al., [38]. In the case that
there is no gas hydrate in the pore space, apparent
porosity as is equal to porosity and Equations
9-11 are identical for the bulk modulus derived by
the Biot-Gassmann theory (BGT). For details of
TPE for GHBS, consult Lee [10].
Figure 6a-b show gas hydrate saturations
estimated from compressional- and shear-wave
velocities using a α = 34.0 and ε = 0.12 (Equations
10-11). The acoustic derived gas hydrate
saturations as depicted in Figure 6a-b are
comparable to those calculated by other means for
units C and D in the Mount Elbert well.
Nuclear magnetic resonance logs
In recent years there have been significant
developments in the field of nuclear magnetic
resonance well logging [reviewed by 5]. Similar
to neutron porosity devices, nuclear magnetic
resonance 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., [33] 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 has been developed which uses
porosities estimated from density and NMR logs
[5]. 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 C (12)
From Equations 2 and 12
h
NMRhD
1 (13)
NMRhC
(14)
where
wma
hw
h
(15)
wma
bma
D
(16)
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 C . The porosity given in Equation
13 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 hydrate saturation log as calculated for the
Alaska Mount Elbert well have been plotted in
Figure 5 for comparison with the resistivity
derived gas hydrate saturation log. The NMR-
density porosity derived gas hydrate saturation log
is also plotted in Figure 6a for comparison with the
acoustic derived gas hydrate saturation logs.
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 [23] and the
Alaska Mount Elbert well [41] 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.,
41]. 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) are very high, in the
multiple Darcy range [41]. The permeabilities in
the hydrate-bearing sand reservoirs, however, are
very low on the order of 0.01 to 0.10 mD.
Anisotropic gas hydrate reservoirs
Recent studies [12, 14] have shown that gas
hydrate saturations estimated from resistivity and
acoustic log data in near vertical fracture systems
(assuming isotropic reservoir conditions) are much
higher than those estimated from pressure core
analysis. To reconcile this difference, Lee and
Collett [12] presented an anisotropic gas hydrate
reservoir model and gas hydrate saturations
estimated from this combined resistivity and
acoustic reservoir model, assuming high-angle
fractures, agreed with saturations estimated from
cores. In Lee and Collett [12] the analysis of
downhole LWD and wireline resistivity log data
from Site NGHP-01-10 in India yielded gas
hydrate saturations greater than 50% to as high as
80% within an apparent fractured dominated gas
hydrate measuring more than 140 m thick. Gas
hydrate saturations estimated from pressure cores
from the same interval at Site NGHP-01-10 were
less than ~25%, in this example it is again
assumed that the pressure cores have yielded
accurate gas hydrate saturations. The primary
cause for the difference in the resistivity-log- and
pressure-core-derived gas hydrate saturations has
been attributed to the anisotropic nature of the
reservoir due to gas hydrate in high-angle
fractures. As shown above, the Archie
relationship can be used to derive accurate gas
hydrate saturations in isotropic reservoirs. Theory
indicates the Archie “cementation constant” m and
the “saturation exponent” n are dependent on the
orientation of the fractures in the reservoir and that
it might be possible to derive unique values for
both of the Archie variables that would in turn
yield resistivity derived gas hydrate saturations
that were more comparable to the estimates from
pressure cores. By using higher values of m and n
in the resistivity analysis for fractured reservoirs,
Lee and Collett [12] was able to significantly
reduce the difference between the resistivity-log-
and pressure-core-derived saturation estimates, but
a sizable difference remained.
To better understand the nature of fractured
reservoirs, Lee and Collett [12] incorporated
wireline compressional- and shear-wave acoustic
wireline log data into their analysis of the Site
NGHP-01-10 gas hydrate occurrence. The
compressional- and shear-wave anisotropic
acoustic model developed by Lee and Collett [12]
consisted of fractures filled with gas hydrate in an
otherwise isotropic medium. Gas hydrate
saturations estimated from compressional-wave
velocities assuming a vertical fracture system
agree better with those estimated from pressure
cores than other models. However, the vertical
fracture shear-wave model derived gas hydrate
saturations still significantly differ from the
pressure core derived gas hydrate saturations due
to uncertainties of tool orientation relative to the
fractures.
SUMMARY
As shown in this review, downhole log data can be
used to obtain highly accurate reservoir porosity
and gas hydrate saturations within a wide range of
gas hydrate reservoir conditions. Electrical
resistivity, acoustic transit-time, and nuclear
magnetic resonance log data have been used to
quantify the amount of gas hydrate in numerous
geologic settings throughout the world. Various
forms of the Archie relation, with special
consideration for nature of the reservoir (grain
supported versus fracture dominated), have
become a standard method for assessing gas
hydrate saturations. It is well known that the
occurrence of shale (clay) in the sediment matrix
of a reservoir can affect the calculation of
hydrocarbon saturations with downhole resistivity
log data. Modified version of standard “shaly-
sand” log analysis models have also been used to
quantify the effects of shale (clay) on resistivity
log derived gas hydrate saturation calculations. It
has also become clear that gas hydrate saturations
derived from resistivity log data, that assume
isotropic conditions, in fracture dominated
reservoirs significantly overestimate the true in-
situ gas hydrate saturation. Only with the
integration of pressure core and downhole acoustic
log data has it become possible to fully
characterize the nature of anisotropic gas hydrate
reservoir systems. The acoustic properties of gas-
hydrate-bearing sediments have received a great
deal of attention. Numerous acoustic models,
including the Lee weighted average equation, the
Kuster-Toksöz wave scattering, the grain contact
model, the effective medium theory, and the Biot-
Gassmann theory, have all been used to model the
acoustic properties of various types of gas hydrate
occurrences in many cases yield highly accurate
gas hydrate saturation data. One of the most
important, but probably simplest developments,
has been the realization that nuclear magnetic
resonance well logs could be used 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. Some of the data used in this
review were provided by the Ocean Drilling
Program and the Integrated Ocean Drilling
Program. We also acknowledge the contributions
from the Mallik 1998 and 2002 Gas Hydrate
Research Projects, the DOE sponsored Gulf of
Mexico Gas Hydrate Joint Industry Project Legs I
and II, the India NGHP Expedition 01, and the
DOE-BP sponsored Mount Elbert drilling project
on the Alaska North Slope. We also wish to thank
Dr. D. Goldberg and the entire staff of the
Borehole Research Group of the Lamont-Doherty
Earth Observatory for their special support and
contributions to the gas hydrate research
community over the last 15 years.
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