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: tcollett@usgs.gov

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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