HomeMy WebLinkAbout4 Characterization of Methane Hydrate
TECHNOLOGY STATUS ASSESSMENT
CHARACTERIZATION AND QUANTIFICATION
OF THE METHANE HYDRATE RESOURCE POTENTIAL ASSOCIATED WITH THE
BARROW GAS FIELDS
DOE Project Number: DE-FC26-06NT42962
Prepared by
Thomas P. Walsh
Peter J. Stokes, P.E.
Dr. Christina Livesey
Petrotechnical Resources of Alaska, LLC
3601 C. Street, Suite 822
Anchorage, AK 99503
Sandra Hamann
Michael McCrum
MWH Americas, Inc
1835 S. Bragaw Street, Suite 350
Anchorage, AK 99508
Prepared for:
U.S. Department of Energy
National Energy Technology Laboratory
626 Cochrane Mills Road
P.O. Box 10940
Pittsburgh, PA 15236-0940
DOE Project No. DE-FC26-06NT42962 i
DISCLAIMER
This report was prepared as an account of work sponsored by an agency of the United States
Government. Neither the Untied States Government nor any agency thereof, nor any of their employees,
makes any warranty, express or implied, or assumes any legal liability or responsibility for the accuracy,
completeness, or usefulness of any information, apparatus, product, or process disclosed, or represents
that its use would not infringe privately owned rights. Reference herein to any specific commercial
product, process, or service by trade name, trademark, manufacturer, or otherwise does not necessarily
constitute or imply its endorsement, recommendation, or favoring by the Untied States Government or
any agency thereof. The views and opinions of authors expressed herein do not necessarily state or
reflect those of the United States Government or any agency thereof.
This Technical Assessment Report was prepared with support of the United States Department of Energy,
under Award No. DE-FC26-06NT42962. Any opinions, findings, conclusions, or recommendations
expressed herein are those of the authors and do not necessarily reflect the views of the Department of
Energy.
DOE Project No. DE-FC26-06NT42962 Page 1
TECHNOLOGY STATUS ASSESSMENT
Introduction
Naturally-occurring gas hydrates are widespread in subsea sediments and in permafrost regions and hold
the promise of producing large volumes of methane gas (Collett, 2004). The U.S. Geological Survey
(USGS) estimated that permafrost-associated gas hydrates on the Alaska North Slope (ANS) may contain
up to 590 trillion cubic feet (TCF) of in-place gas (Collett, 1995), with the volume of gas within known
gas hydrates of the Prudhoe Bay-Kuparuk River infrastructure area alone exceeding 100 TCF (Collett,
2004). If this assessment is valid, the amount of natural gas stored as gas hydrates in northern Alaska
could be up to seven times larger than the estimated total remaining recoverable conventional natural gas
resources in the entire United States (Collett, 1997). The U.S. Department of Energy (DOE) National
Energy Technology Laboratory (NETL) predicts that the gas hydrate resources closest to potential
commercialization are those existing at high saturation within quality reservoir rocks under existing
Arctic infrastructure. This assertion clearly points toward the hydrate accumulations overlying the
Prudhoe Bay and Kuparuk Oil Fields as potential future commercial resources, although the only
currently commercially produced gas fields on the North Slope, the Barrow Gas Fields, may also prove to
be viable methane hydrate commercialization opportunities in the near future.
Occurrence of methane hydrate resources have been postulated in association with the Walakpa Gas
Field, south of the village of Barrow, Alaska (Glenn and Allen, 1991 and Collett, 1992), and there is
sufficient information available to model reservoir conditions to characterize and quantify the postulated
methane hydrate resource. This project seeks to: establish the presence of a hydrate stability zone
associated with the Barrow Gas Fields; fully and accurately characterize the methane hydrate resource;
select an optimal location for drilling a dedicated hydrate test well; and model the gas and water
production from a dedicated test well drilled in the free gas-charged reservoir directly beneath the
methane hydrate/free gas interface. Results of recent research into hydrate occurrence, characterization,
and producibility in the Alaskan, Canadian and Russian arctic regions have significantly advanced the
understanding of this resource, and the current study will utilize and attempt to build on this advancing
base of knowledge.
Current State of Information.
Significant effort has been undertaken to understand the character of natural gas hydrate accumulations in
the Alaskan North Slope (ANS) since their existence was confirmed at the NW Eileen #2 well in 1972
(reviewed by Kvenvolden and McMenamin, 1980). A very significant milestone in the study of ANS
methane occurred in February, 2007, when the first extensive core of hydrate-bearing sediment was
recovered from the Mt. Elbert well at Milne Point Field on Alaska’s North Slope (BP press release,
2007). The required elements necessary for the occurrence of methane hydrate are widespread across the
ANS (Collett, 2004). So far, there is only inferential evidence for the presence of gas hydrate in the area
of the Barrow Gas Fields, such as: presence of permafrost to a depth of 800-1300 ft. (Glenn and Allen,
1991, and Collett and others, 1989); free methane gas beneath the permafrost; hydrate formation in
production wellbores; and material balance model results which indicate a reservoir energy source other
than gas expansion. It is the goal of this study to integrate all available geoscience and production
information available for the Barrow Gas Fields, in a framework supported by relevant ongoing and prior
hydrate studies to quantify the methane hydrate resource potential in the Barrow area.
Occurrence of hydrates in the subsurface depends on a number of factors, including: appropriate reservoir
pressure and temperature regime; suitable gas and formation water in a porous reservoir layer, which
DOE Project No. DE-FC26-06NT42962 Page 2
either has a geologic trapping mechanism, or is self-trapping by formation of hydrates; and critical timing
of all the aforementioned elements.
Direct evidence for the presence of hydrates in the subsurface is obtained by collecting samples of the
hydrate through coring. Indirect methods for detecting hydrates include interpretation of geological,
geochemical and geophysical information (Paul, and Dillon, 2001).
Geologic evidence of gas hydrate presence is typically accomplished through interpretation of wireline
logs, although these techniques are somewhat qualitative, and not optimized for hydrate analysis, but
adapted from conventional oil and gas techniques (Collett, 1992). The USGS reports that the major issue
in detecting gas hydrate from well logs is that gas hydrate and water ice permafrost have the same
responses for the standard basic logs (Collett, 1998). Hole conditions for logging can also be poor due to
thawing by drilling mud and subsequent enlargement of the hole in unconsolidated formations. The
gamma ray, neutron and density logs respond normally and can be interpreted for lithology and porosity.
The resistivity log sees both water ice and gas hydrate as non-conductive, and estimates of the amount of
pore space filled by solid ice or gas hydrate can be attempted. The major source of error in this approach
is knowledge of the formation water salinity, assuming some water remains unfrozen to provide the
conductivity seen by the logging tool. In the proposed project area, salinities are known to be low at
shallow depths (2000 to 6000 ppm). In calculating the corresponding resistivity (Rw) at 2000 ft. for these
salinities at the formation temperatures, the possible error in calculated water saturations due to
uncertainties in salinity and temperature could easily be a factor of two. There is a lack of core laboratory
studies to quantify the range of gas hydrate saturations or the parameters suitable for use in log saturation
calculations (ibid).
Gas hydrate and ice permafrost on the ANS show high acoustic velocities and low transit time compared
with unfrozen formations. Base permafrost is usually picked where the resistivity reduces to a consistent
value less than about 50 ohm-m and the sonic transit time at that point increases in the sands from around
100 µs/ft to 140-150 µs/ft (Collett and others, 1989). Gas hydrate within the permafrost is very difficult
to distinguish from water ice.
Geochemical detection involves analysis of formation water and gas composition and isotopic
fractionation to determine the presence of hydrate gas, the source of the gas, and the processes leading to
the formation and dissociation of the hydrate (Paull and Dillon, 2001). Pore water freshening, coupled
with presence of large amounts of methane has been documented as an indicator of hydrate occurrence
(Hesse and Harrison, 1981). Gas composition and isotopic analysis is available for the Barrow Gas
Fields, as well as formation water analysis, and this information will be integrated in the study, in the
context of the significant findings of global hydrate studies.
The pressure and temperature conditions under which gas hydrate exist have been reported for both
methane hydrate and gas with heavier components. Produced gas from the Walakpa Gas Field is
approximately 97% methane, 2% ethane, and around .3 % propane, and an earlier study of methane
hydrate resource potential indicated that the base of the hydrate stability zone in the Walakpa Gas Field
could exceed 2,000 ft. (Glenn and Allen, 1991). The salinity of the water in which gas hydrate forms may
also affect the range of gas hydrate stability, with increasing salinity reducing the range (Wright and
Dallimore, 2004). Because formation water salinities at shallow depths in the Barrow Gas Field region are
low, this effect is expected to be small.
Modeling of the gas hydrate stability zone to incorporate detailed gas and formation water composition,
and gas hydrate structure can be accomplished using tools such as HWHYD developed at Heriot-Watt
University, or CSMHYD, developed at Colorado School of Mines. Modeling gas hydrate stability based
on known compositional characteristics and geothermal and pressure gradients provides a valuable means
DOE Project No. DE-FC26-06NT42962 Page 3
of indicating the probable presence or absence of gas hydrate in the subsurface. (Heriot-Watt University,
2006).
One critical requirement for the formation of in-situ hydrates in the subsurface is that the formation
temperature must be below the hydrate stability temperature at the depth of the formation, based on the
known phase behavior of hydrates. Permafrost is characteristic of suppressed mean surface temperature,
and decreased geothermal gradient, and therefore, thicker permafrost can be linked to thicker hydrate
stability zone (Holder and others, 1987). The permafrost zone thins from east to west along the North
Alaskan coast (Lachenbruch and others, 1988 and Collett and others, 1989), leading to a thinner hydrate
stability zone. One key objective of this study is to determine whether or not the hydrate stability zone in
the Barrow Gas Fields is thick enough to intersect with gas-bearing reservoir formation, and all available
temperature log and wireline log information will be analyzed in order to accurately determine the
geothermal gradient, and depth to base permafrost and base hydrate stability zone.
Gas samples have been collected and analyzed on several occasions for gas produced from the Barrow
Gas Fields, and compositional and isotopic analysis of samples from 9 wells (three from each field) is
currently underway as part of this study. The results of this analysis will be incorporated in hydrate
stability zone modeling for the three fields, as well as utilized for geochemical investigation which may
help to infer the presence of methane hydrates.
Highly Relevant Recent/Ongoing Projects
The current state of information on gas hydrates in permafrost has been greatly advanced by recent
projects conducted in Alaska and Canada. As summarized below, these multi-phase projects represent the
first efforts to verify theoretical and laboratory-based results using geologic, geophysical and production
data collected in areas known to contain gas hydrate accumulations. The results and techniques
incorporated in these studies will significantly influence the direction and goals of this study.
The Mallik 2002 Consortium: Drilling and Testing a Gas Hydrate Well project began in 1998, with the
first research wells to core hydrate bearing sediment and production testing of the hydrate-bearing
reservoir. In 2001 - 2002, a production research well and two observation wells were drilled in the
Canadian Mackenzie Delta. Full-scale field experiments monitored the physical behavior of the hydrate
deposits in response to depressurization and thermal stimulation. A depressurization test was achieved by
a series of MDT tests, and a thermal method was successfully tested using circulation of a heated fluid
and measuring the recovery of gas dissociated due to the addition of heat. The results of the Mallik
testing were used to develop and calibrate a gas hydrate production simulator, and the simulator was used
to make long term production predictions (Collette 2005). Simulation results show that cumulative
production from hot water injection will be possibly two times higher than simple depressurization, but
that depressurization could still recover significant amounts of gas potentially without the capital cost of
thermal injection facilities. Validated with data from Mallik, the ToughFX/Hydrate model allows
simulation of hydrate dissociation and resultant fluid flows under currently contemplated production
scenarios (Boswell, 2005). (GSC et al. 2004; Osadetz, 2003; DOE Project No. DE-AT26-97FT34342 and
DE-AC26-01NT41007 technical and status reports).
The ongoing Alaska North Slope Gas Hydrate Reservoir Characterization project was initiated in 2002 to
determine reservoir extent, stratigraphy, structure, continuity, quality, variability, and geophysical and
petrophysical property distribution in a known gas hydrate area of the ANS. Relevant findings include:
• Regional structural mapping of reservoir units, the mapping of shallow fault offsets, and
determination of syndepositional faulting and fault-seal potential.
DOE Project No. DE-FC26-06NT42962 Page 4
• Adaptation of the commercial modeling package CMG STARS to provide reservoir modeling
capabilities for hydrate prospects; use of the model to determine production potential of various gas
hydrate settings.
• Geophysical modeling that enabled the correlation of seismic attributes with critical hydrate reservoir
parameters (e.g., zone thickness and hydrate saturation).
• Seismic modeling of shallow velocity fields (<950 ms) that suggested that both amplitude and
waveform variations may help locate has hydrate-bearing reservoirs
• Use of Landmark software suite to integrate and analyze detailed log correlations, specially processed
log data, gas hydrate composition information, and specialized 3-D seismic volumes.
(DOE Project Nos. DE-AT26-97FT34342 and DE-FC-01NT41332 topical and status reports.
Reports/abstracts from AAPG Hedberg Research Conference, Natural Gas Hydrates: Energy Resource
Potential and Associated Geologic Hazards, September 12-16, 2004.)
As part of the Methane Hydrate Production from Alaskan Permafrost project, the HOT ICE well was
drilled in 2003-2004 for the purpose of developing and testing new methods of drilling and recovering
methane hydrates. The well was completed at a depth of 2,300 feet, which is approximately 300 feet
below the gas hydrate stability zone. Gas-bearing sands were encountered in highly porous sandstones
that were situated within the hydrate stability zone. The research team also acquired a 3-D Vertical
Seismic Profile at the well, which resulted in very high resolution images of the subsurface, and possible
indications of hydrate updip and east of the well site. Analyses of the core, log, and seismic data from the
well indicate that the hydrate in this region occurs in patchy deposits and may require a high methane flux
from the subsurface in order to form more continuous drilling prospects. (DOE Project No. DE-FC26-
01NT41331, topical and status reports. Reports/abstracts from AAPG Hedberg Research Conference,
Natural Gas Hydrates: Energy Resource Potential and Associated Geologic Hazards, September 12-16,
2004).
This collection of recently-funded DOE studies has contributed to the understanding that hydrates most
often occur as discrete grains that form within pores and act as part of the framework of the sediment
rather than as grain coatings or cements. This finding is critical to improving the interpretation of well
log, reflection seismic data, and a variety of other reservoir parameters (Boswell, 2005).
Another project worth noting is the West Siberian Messoyakha Gas Field, which has been suggested to be
an example of a hydrate accumulation currently in commercial production using conventional production
methods. The production history of this field has been proposed as evidence that the hydrate resource is
being depleted by depressuring the free gas accumulation beneath a hydrate-bearing zone, thus
dissociating the gas hydrates. This is of significance to the Barrow Gas Field Study, in that the proposed
production model involves drilling a horizontal development well in the free gas interval in close
proximity to the hydrate-free gas interface. However, recent studies indicate that the contribution to
production from hydrates in Messoyakha may have been overestimated (Ginsburg, 1993; and Collett and
Ginsburg, 1998).
Other sources of information relevant to the subject project include: 1) Comparative Assessment of
Advanced Gas Hydrate Production Methods – a current project that will provide a better understanding of
the methane hydrate dissociation process and methane migration towards the wellbore. (DOE Project No.
DE-FC26-06NT42666 documentation); and 2) Stability Zone of Natural Gas Hydrates in a Permafrost
Bearing Region of the Beaufort-Mackenzie Basin: Study of a Feasibility Energy Source -- An analysis
of geological and geophysical data from 150 wells in the Beaufort-Mackenzie region leading to
reinterpretation of the depth of methane hydrate stability and construction of the first contour maps
displaying thickness of hydrate stability zones below permafrost. (GSC, October 2004).
DOE Project No. DE-FC26-06NT42962 Page 5
Development Strategies
While gas hydrate represents a very significant potential resource on the ANS, adequate production
testing has not proven the feasibility of commercial production and the recovery factory has not been
quantified. Problems being addressed by ongoing and proposed research on the ANS are: 1) can gas
hydrate accumulations be identified and delineated; 2) can natural gas be produced from gas hydrate; and
if so, 3) in what quantities and at what rate?
Three approaches proposed for the production of gas from gas hydrate are: thermal injection; chemical
injection, and depressurization; (Collette, 2004). The Mallik project included a depressurization test, and
a thermal method was also successfully tested. Simulation results show that cumulative production from
hot water injection will be possibly two times higher than simple depressurization, but that
depressurization could still recover significant amounts of gas potentially without the capital cost of
thermal injection facilities (Collett, 2005). The results of prior DOE studies (DOE Project No. DE-FG21-
91MC28131) suggest the presence of gas hydrates in the Barrow area gas fields. This project includes a
two-phase study to better understand the nature and occurrence of gas hydrates in the Barrow gas fields,
and to evaluate the potential influence of gas hydrates as a recharge mechanism for gas supply and
production.
Phase 1 will incorporate previous research results (Glenn and Allen 1991) with the current knowledge
base to quantify the probability that methane hydrates exist in association with the Barrow gas fields. A
hydrate stability zone model, incorporating detailed gas composition, formation water salinity, and
formation pore pressure and temperature gradient information will be utilized to define the depth ranges
of the hydrate stability zone in the area of the Barrow Gas Fields. If the results of this work provide
compelling evidence for a hydrate accumulation, the available seismic, well and production history
information will be used to characterize the reservoir and its fluids. A static reservoir model will be
constructed to establish reservoir boundaries, pore fluid properties, and pressure and temperature
conditions. This detailed reservoir characterization will be used to choose an optimum location and
configuration for a dedicated gas hydrate test well, and as input to dynamic production simulation
modeling.
Phase II of the project will include drilling a test well, producing gas hydrate indirectly through
production of free gas from beneath the free gas/gas hydrate interface. The free gas/gas hydrate interface
will be monitored during production to help establish the contribution to the free gas zone from gas
hydrates. The proposed production method involves extracting gas from the hydrates through
depressurization. Data collected from the test well will be used as input to the reservoir model to confirm
whether gas hydrates are contributing to gas produced from the free gas zone.
Future Implications
Verifying the presence of a significant gas hydrate accumulation in the gas fields of Barrow will provide
an opportunity to test the potential of producing gas hydrates through depressurization. Modeling results
will contribute to the current understanding of the gas hydrate stability zone and whether that zone is
associated with or perhaps contributing to production from the Barrow Gas Fields. Ultimately, this study
will provide unique insight into the role played by gas hydrate in recharging a producing gas field and
will provide a platform for continued development of the tools and technologies developed by previous
gas hydrate research. It has been suggested that if hydrates are a factor in the resource potential of the
Barrow Gas Fields, the remaining reserves base of the Walakpa Gas Field could be several orders of
magnitude greater than current estimates (Collett, 1998).
DOE Project No. DE-FC26-06NT42962 Page 6
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