U.S. patent application number 10/728618 was filed with the patent office on 2004-10-14 for method of sequestering carbon dioxide while producing natural gas.
Invention is credited to Piekenbrock, Eugene J..
Application Number | 20040200618 10/728618 |
Document ID | / |
Family ID | 33134869 |
Filed Date | 2004-10-14 |
United States Patent
Application |
20040200618 |
Kind Code |
A1 |
Piekenbrock, Eugene J. |
October 14, 2004 |
Method of sequestering carbon dioxide while producing natural
gas
Abstract
A method of sequestering carbon dioxide and producing natural
gas including: (a) injecting an injectant containing at least some
amount of carbon dioxide into a zone containing natural gas
hydrates; (b) releasing natural gas from the hydrates by allowing
thermal transfer and pressure changes from the injectant to the
hydrates; and (c) sequestering the carbon dioxide in the zone that
previously contained the natural gas hydrates.
Inventors: |
Piekenbrock, Eugene J.;
(Anchorage, AK) |
Correspondence
Address: |
BLACK LOWE & GRAHAM, PLLC
701 FIFTH AVENUE
SUITE 4800
SEATTLE
WA
98104
US
|
Family ID: |
33134869 |
Appl. No.: |
10/728618 |
Filed: |
December 4, 2003 |
Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
|
|
60430961 |
Dec 4, 2002 |
|
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|
Current U.S.
Class: |
166/305.1 ;
166/309 |
Current CPC
Class: |
E21B 41/0057 20130101;
Y02C 20/40 20200801; E21B 41/0064 20130101; E21B 43/164 20130101;
E21B 41/0099 20200501; Y02C 10/14 20130101; Y02P 90/70
20151101 |
Class at
Publication: |
166/305.1 ;
166/309 |
International
Class: |
E21B 043/26 |
Claims
The embodiments of the invention in which an exclusive property or
privilege is claimed are defined as follows:
1. A method of sequestering carbon dioxide and producing natural
gas comprising: (a) injecting an injectant containing at least some
amount of carbon dioxide into a zone containing natural gas
hydrates; (b) releasing natural gas from the hydrates by allowing
thermal transfer and pressure changes from said injectant to the
hydrates; and (c) sequestering the carbon dioxide in the zone that
previously contained the natural gas hydrates.
2. The method of claim 1 wherein said injectant is a liquid.
3. The method of claim 1 wherein said injectant is a mixture of
carbon dioxide and methane.
4. A method of sequestering carbon dioxide while at the same time
producing natural gas comprising: (a) drilling and completing at
least one well in a subterranean formation where there resides
natural gas hydrates; (b) supplying an injectant stream of a
desired composition containing at least some carbon dioxide; (c)
pumping said injectant into said well to the appropriate depth and
at a controlled temperature and pressure; (d) circulating said
injectant to said natural gas hydrates to cause dissociation of
said natural gas hydrates to release free natural gas; (e)
collecting the evolved natural gas and transporting said natural
gas to the surface; and (f) allowing at least part of said carbon
dioxide to be sequestered in said subterranean formation.
5. The method of claim 4 wherein said injectant is a liquid.
6. The method of claim 4 wherein said injectant is a mixture of
carbon dioxide and methane.
7. A method of sequestering carbon dioxide while at the same time
producing natural gas comprising: (a) drilling and completing at
least one well into a subterranean formation containing natural gas
hydrates; (b) supplying a gas injectant from a gas/injectant
supply; (c) continuously controlling and monitoring the
gas/injectant supply to provide for the initiation, continuation,
and/or shutdown of injection and production; (d) injecting said
injectant within said subterranean formation as a liquid so that
heat transfer from said injectant is highly efficient, so that the
pressure change and the rate of dissociation of said natural gas
hydrates allows said natural gas hydrates to dissociate to free
natural gas and to migrate said natural gas via gravity/density
segregation to said production well, and without breaching the
subsurface containment with fractures that would allow significant
depressurization of the injectant so that the injectant cannot
remain a liquid; and (e) producing said hydrate-evolved natural gas
that has migrated to the production well by gravity/density
segregation of the hydrate-evolved natural gas from the injectant,
whereby the injectant containing at least some carbon dioxide
remains in said subterranean formation where, after the final
production stages, the pressure and temperature are allowed to
reduce whereby said injectant changes phase to a hydrate.
8. The method of claim 7 wherein said injectant is a mixture of
carbon dioxide and methane.
9. A system for sequestering carbon dioxide and producing natural
gas from subterranean natural gas hydrates by a controlled
injection of an injectant stream that contains at least some carbon
dioxide, comprising: (a) a gas supply subsystem for preparation and
injection of the injectant stream into a well; (b) a well subsystem
for delivering the injectant into the subsurface formation and for
producing the resultant natural gas; (c) a subsurface containment
subsystem comprising a subsurface formation with static and dynamic
permeability variations that form barriers to the circulation of
gas and liquids; and, (d) a monitoring and control subsystem for
maintaining the production process and for controlling the
injection and production pressure and temperature for the natural
gas production and carbon dioxide capture and sequestration in the
subsurface formation.
10. The system of claim 9 wherein said injectant stream is a
mixture of carbon dioxide and methane.
Description
CROSS-REFERENCE TO RELATED APPLICATION
[0001] This application claims the benefit of U.S. Provisional
Application No. 60/430,961 filed Dec. 4, 2002.
FIELD OF THE INVENTION
[0002] This environmental-quality invention is in the field of
apparatus and methods for sequestering greenhouse gases while
producing natural gas from natural gas hydrates in a subterranean
formation. The invention enhances the quality of the environment of
mankind by contributing to the control of greenhouse gases.
BACKGROUND OF THE INVENTION
[0003] Hydrates are solid crystalline compounds, commonly known as
clathrates. These crystalline compounds are formed of a "cage like"
structure of water surrounding other molecules which are often
gases (for example, methane, carbon dioxide) and whose structure is
dependent on the size of the contained molecule. A thorough
description of hydrates is contained in E. D. Sloan, Jr., Clathrate
Hydrates of Natural Gases, Dekker N.Y. (1990). Natural gas hydrates
are those hydrates formed from gases found in natural gas
reservoirs. Natural gas hydrates have many properties similar to
ice.
[0004] Several models and descriptions of the occurrence of natural
gas hydrates have been put forward in the literature and depend on
the following factors: (a) the phase stability of the hydrate in
terms of pressure and temperature; (b) the nature of occurrence of
the natural gas hydrate in clastic sediments (for example, either
clay or sand rich sediments); and, (c) the occurrence of the
natural gas hydrate above or below ice-bearing permafrost, or the
occurrence in marine-continental shelf or arctic-permafrost
settings.
[0005] The discussion of recovering hydrates with respect to the
present invention focuses on moderate to low clay content clastics
that bear hydrates in a subterranean formation (either in
arctic-permafrost or marine-continental shelf locations) where the
hydrates are trapped in pores (of the clay or sand particles) that
are of sufficient size after hydrate and/or ice dissociation as to
provide permeability sufficient for production in a timely manner.
In all likelihood, the best hydrate zones would be those below
ice-bearing permafrost due to the added impact of ice dissociation
on the overall energy requirements for production.
[0006] In the scientific literature, no model is put forward to
explain how the hydrates occupy the pore space in the clastics.
However, if the hydrates occupy a significant volume of the pore
space they will reduce the permeability by several orders of
magnitude. After hydrate dissociation, these previously
hydrate-filled pores will improve heat transfer from convective
flow through the reservoir and provide expanded heat transfer via
conductive heat into the subterranean formation.
[0007] The pressure and temperature ranges for natural gas hydrate
stability depends on the gas that is trapped in the hydrate. FIGS.
4A-4F show the stability ranges for two gases: methane and carbon
dioxide. Methane is the most commonly occurring gas in natural gas
hydrate deposits and in most places is greater than 98 mole % of
the natural gas hydrate found.
[0008] Several methods of producing natural gas from hydrates have
been suggested for clastic deposits:
[0009] 1. Thermal stimulation
[0010] (a) Steam, hot gas, hot water, and hot brine
[0011] (b) In place combustion, electrical, radio wave or microwave
heating
[0012] 2. Depressurization
[0013] 3. Hydrate inhibitor injection
[0014] 4. Combinations of depressurization and thermal
simulation
[0015] Also several enhancement methods such as fracturing or
drilling with jet pumps have been suggested, or selecting a
formation with a free gas zone. Free gas zones exist at the base of
many hydrate bearing zones and provide a pathway for flow when the
gas hydrate dissociates.
[0016] Hydrates of natural gas occur where the temperature and
pressure ranges are appropriate for their stability and the
occurrence of natural gas exists. Hydrates are both biogenic and
thermogenic. Biogenic hydrates are derived from biological
activity. Many of the biogenic hydrates exist where biological
activity in the past has produced methane gas and this gas has been
in many different manners moved into the hydrate phase stability
window. Thermogenic hydrates are derived from the thermal response
through geologic time of burial of carbon rich sediments and
subsequent hydrocarbon production. Thermogenic hydrates are
associated with major hydrocarbon occurrences where the natural
gases similar to the biogenic gases have been moved into the
hydrate phase stability window.
[0017] The phase stability window for the ice-like crystalline
solid in hydrate exists in two primary locations: regions with
permafrost and regions on the continental shelf. The occurrence of
hydrate in these regions is enhanced in areas where thermogenic
gases available from deeper hydrocarbon deposits have migrated into
the stability range, for example, the North Slope of Alaska or the
Gulf of Mexico.
[0018] The estimates of hydrates as resource usually include
estimates of all occurrences of the resources including the
resource where it is probably not developable due to association
with sediments high in clay content. The hydrate cores in the
Mallik well in the McKenzie Delta, Canada showed that significant
resources exists in low to moderate clay clastic formations that
can be approached with similar technology used in hydrocarbon
recovery.
[0019] Key gases believed to have greenhouse gas effects are carbon
dioxide (CO.sub.2), methane (CH.sub.4), and nitrous oxide
(N.sub.2O). These gases are naturally occurring and make up less
than one tenth of one percent of the gases in the atmosphere. The
atmosphere consists mainly of nitrogen at 78 percent and oxygen at
21 percent. Greenhouse gases are believed to trap heat in the
atmosphere and without them it has been estimated that the earth's
surface would be significantly colder than it is today. Concern
exists that the further release of greenhouse gases will cause a
further increase in atmospheric temperature.
[0020] In the past, major concern has focused on the emission of
carbon dioxide from burning coal, oil, and natural gas. Recently
the release of methane to the atmosphere has come under scrutiny
and concern. Methane gas may have significantly more impact than
carbon dioxide gas on the atmosphere. Estimates in the literature
suggest methane has a 12-20% greater efficiency for the proposed
greenhouse gas phenomena.
[0021] Numerous authors have suggested that hydrate deposits may be
accessible to future release of greenhouse gases. It has been
suggested that the geologic record provides evidence that
potentially large volumes of greenhouse gases in the past, in
particular methane, have been released into the atmosphere because
of sea level changes and that these changes impacted the global
temperature. While those past changes are not those potentially
brought on by man, they nonetheless suggest that global atmospheric
changes may have taken place because of methane hydrate
dissociation. The fear is that current dissociation of methane
hydrate, which is a more efficient greenhouse gas, will accelerate
the supposed rate of warming.
[0022] Since methane hydrates provide a very clean source of
energy, they may provide the most environmentally acceptable
pathway to non-oil hydrocarbon energy. It may also be beneficial to
remove the methane from these hydrate deposits and replace it with
carbon dioxide irrespective of whether it is man or nature causing
the period of warming that many scientists have suggested.
DESCRIPTION OF PRIOR ART
[0023] The sequestration of carbon dioxide in aquifers has been
described in patents such as U.S. Pat. No. 5,397,553 to Spencer and
U.S. Pat. No. 5,261,490 to Ebinuma et al. In the injection or
production of natural gases in wells that pass through the
temperature and pressure regime where hydrates are stable and exist
(where the hydrocarbons are in an immobile form), several
production techniques have been patented and discussed in the
literature. Some of the patents in this area are U.S. Pat. No.
5,950,732 to Agee et al.; U.S. Pat. No. 5,713,416 to Chatterji et
al.; U.S. Pat. No. 4,007,787 to Cottle; U.S. Pat. No. 5,261,490 to
Ebinuma et al.; U.S. Pat. No. 4,424,858 to Elliot et al.; U.S. Pat.
No. 4,376,462 to Elliot et al.; U.S. Pat. No. 4,262,747 to Elliot
et al.; and U.S. Pat. No. 3,920,072 to Kern.
[0024] Heretofore in the production of natural gas through
permafrost or intervals with pressure and temperature regime where
hydrates exists, the zone would have to be insulated, refrigerated,
or the like. Thawing of the permafrost is to be avoided as well
casing collapse is then an issue to be addressed. Some of the
patents in this area are U.S. Pat. No. 5,816,325 to Hytken;
JP10317869A2 to Kazuyuki; U.S. Pat. No. 5,291,956 to Mueller et
al.; U.S. Pat. No. 4,595,057 to Deming et al.; U.S. Pat. No.
4,399,867 to Wolcott; U.S. Pat. No. 3,220,470 to Balch; and U.S.
Pat. No. 2,148,717 to Whitney.
[0025] Proposed methods and apparatus for the capture of carbon
dioxide to remove carbon dioxide as a greenhouse gas have been much
discussed in the literature and many techniques exist. For example,
DOE/EIA-0573 (2000) Emissions of Greenhouse Gases in the United
States 2000, November 2001; S. Kim et al., Potential for Advanced
Carbon Capture and Sequestration Technologies in a Climate
Constrained World, Battelle Pacific Northwest National Laboratory
(PNNL)-13095 (February 2000). Removal of carbon dioxide from
natural gas has been around for years and is a mature
technology.
[0026] The various sources of carbon dioxide gas in the present
invention require the carbon dioxide to be in a gas, such as found
in produced natural gas, in effluent from the combustion of oxygen
and hydrocarbons, in effluent from fuel cell chemical reactions
that convert hydrocarbons to electricity, or in effluent from a gas
to liquid process. However, no active method for the sequestration
of carbon dioxide into hydrate bearing subterranean zones
exists.
[0027] S. Kim et al., cited above, state that:
[0028] "The present state of carbon capture and sequestration
technology is focused on the capture of carbon dioxide (CO.sub.2)
from the flue gas of fossil-fuel electric power plants and the
disposal of the captured CO.sub.2 in various geological formations.
Great attention has been placed recently on the technology for
CO.sub.2 capture from stationary power plants, and several
technologies exist today to capture CO.sub.2 from flue gases.
Capturing CO.sub.2 from power plants is not a new idea and has its
origins as sources of CO.sub.2 for enhanced oil recovery and for
agricultural CO.sub.2 fertilization in greenhouse
applications."
[0029] "According to Herzog et al. [H. Herzog et al., CO.sub.2
Sequestration: Opportunities and Challenges, Massachusetts
Institute of Technology, Cambridge, Mass. (1999)], the current cost
of CO.sub.2 capture from coal and natural gas power plants is 66 to
282 dollars per tonne of carbon ($/tC) avoided depending on the
specific type of power plant. The additional capital, fuel,
operations, and maintenance costs of CO.sub.2 capture add 1 to 3
cents per kWhr to the electricity cost of base plants. Part of the
cost of CO.sub.2 capture is due to energy requirements of the
capture process that result in net power losses. Such energy
penalties can range from 13 to 37 percent depending on the plant
type. Current capture technologies, however, can remove 75 to 90
percent of the CO.sub.2 emitted from the combustion of fossil fuels
. . . "
[0030] "Current demonstration of CO.sub.2 sequestration for the
sole purpose of combating climate change lies with Statoil, a
Norwegian oil company. Induced by a Norwegian carbon tax of 50
dollars per tonne of CO.sub.2 (183 $/tC), the first commercial
CO.sub.2 capture and sequestration facility started operation in
September 1996 by Statoil. CO.sub.2 from a natural gas field is
sequestered into a sandstone aquifer one kilometer beneath the
North Sea. The CO.sub.2 is injected from a floating rig at a rate
of 20,000 tonnes per week which corresponds to the rate of CO.sub.2
produced from a 140 MWe coal-fired power plant."
[0031] "According to Herzog, the cost of Statoil's sequestration
operation alone is 15 dollars per tonne of CO.sub.2 (55 $/tC).
Other than the experiences discussed above, there are no large
scale commercial carbon capture and sequestration technologies
currently deployed."
[0032] "Combining the above capture costs and Statoil's
sequestration cost, the total cost of CO.sub.2 capture and
sequestration ranges from 121 to 337 $/tC. Unless there are carbon
control policies like the Norwegian carbon tax, such high CO.sub.2
capture and sequestration costs are not likely to provide
incentives for the deployment of these technologies."
[0033] Similarly, the methods and apparatus proposed for the
production of hydrates from subterranean formations are many
(Sarish L. Patil, "Overview of Gas Hydrate Production Technology",
May 23, 2002, SPE-AAPG Western Region Meeting, Anchorage, Ak.; D.
Khairkhah et. al., "The Production potential of the Mallik field
reservoir", Geologic Society of Canada Bulletin 544, 1999, pp.
377-399; E. D. Sloan, Jr. "Clathrate Hydrates of Natural Gases" 2nd
Edition revised and expanded, 1998, pp. 513-537). Much
documentation exists concerning the many workable and unworkable
schemes for the production of hydrates and at the same time the
applicable practice of the art of hydrocarbon recovery is
widespread. However, no active production technique exists for the
production of hydrocarbons from hydrates in subterranean zones. The
Messoyakha field in the West Siberian Basin of the former Soviet
Union has been speculated to have produced from hydrates which
exist above a free gas level, but the data is ambiguous.
[0034] Despite all of these mature technologies, the art of
sequestering carbon dioxide and the art of producing hydrates have
not been undertaken jointly.
SUMMARY OF THE INVENTION
[0035] In a broad aspect, the invention is a method of sequestering
carbon dioxide and producing natural gas including: (a) injecting
an injectant containing at least some amount of carbon dioxide into
a zone containing natural gas hydrates; (b) releasing natural gas
from the hydrates by allowing thermal transfer and pressure changes
from the injectant to the hydrates; and (c) sequestering the carbon
dioxide in the zone that previously contained the natural gas
hydrates.
[0036] One embodiment of the invention is a method of sequestering
carbon dioxide while at the same time producing natural gas. This
embodiment includes: (1) drilling and completing at least one well
in a subterranean formation where there is at least some natural
gas in the form of natural gas hydrate; (2) supplying an injectant
stream of a desired composition containing at least some carbon
dioxide; (3) pumping the injectant into the well to the appropriate
depth and at a controlled temperature and pressure; (4) circulating
the injectant to the natural gas hydrate to cause dissociation of
the natural gas hydrate to release free natural gas vapor; (5)
collecting the evolved natural gas and transporting it to the
surface; and (6) allowing at least part of the carbon dioxide to be
sequestered in the subsurface location.
[0037] The present invention, by combining the processes of methane
production and sequestration of carbon dioxide, will make the cost
of sequestration of carbon dioxide and the cost of hydrate
production become competitive. Gravity/density segregation of the
liquid injectant (containing carbon dioxide) from the methane gas
produced from in-situ hydrate dissociation allows production of
methane and entrapment of the liquid carbon dioxide injectant. The
temperature and pressure conditions that form a solid clathrate
from the injectant containing the carbon dioxide are reached by a
change in pressure through production or injection by allowing
reassertion of the regional temperature profile. Thus, the carbon
dioxide is sequestered.
[0038] The process includes:
[0039] 1. Drilling and completing at least one well into a
subterranean formation where there is at least some natural gas in
the form of hydrate;
[0040] 2. Supplying gas/injectant from the gas injectant supply
subsystem to be injected into the well at the appropriate depth and
at the controlled temperature and pressure and composition;
[0041] 3. Controlling and monitoring the gas/injectant supply
subsystem, the well subsystem, and the subsurface containment
subsystem to provide for the initiation, continuation, or shutdown
of injection and production;
[0042] 4. Injecting the injectant within the subsurface containment
subsystem as a liquid so that heat transfer from the injectant is
highly efficient, and so that the pressure change and the rate of
dissociation of natural gas hydrate in place allows the natural gas
hydrate to dissociate to free natural gas as a vapor and to migrate
via gravity/density segregation (while being constrained by the
subsurface containment subsystem) to a production well or wells; an
injection pressure that is above the fracture pressure is allowed
if the fractures formed do not breach the subsurface containment
subsystem; and
[0043] 5. Producing the hydrate-evolved natural gas that has
migrated to the production well while allowing gravity/density
segregation of the hydrate-evolved natural gas from the injectant
so that the injectant containing carbon dioxide (all or in part)
remains in the subsurface containment subsystem where, after the
final production stages, the pressure and temperature are allowed
to reduce to where the injectant can change phase to a hydrate; the
produced natural gas is sent to the production facility or the
produced natural gas is recycled (all or in part) with the gas
supplied for injection from the gas/injectant supply subsystem. The
natural gas may be further processed for removal of water and
separation of methane and carbon dioxide before being supplied to
the gas/injectant supply subsystem or the production facility.
[0044] Another embodiment of the invention is a system for
sequestering carbon dioxide and producing natural gas from a
subterranean natural gas hydrate by means of a controlled injection
of an injectant stream that contains at least in part carbon
dioxide. This injectant stream is cycled/injected into a
subterranean formation that underlies either ocean or land. The
system includes: (a) a gas supply subsystem for preparation and
injection of the injectant stream into a well; (b) a well subsystem
for delivering the injectant into the subsurface formation and for
producing the resultant natural gas; (c) a subsurface containment
subsystem including a subsurface formation with static and dynamic
permeability variations that form permeability barriers to the
circulation of gas and liquids; and, (d) a monitoring and control
subsystem for maintaining the production process and for
controlling the injection and production pressure and temperature
suitable for the desired outcome of methane production and carbon
dioxide capture and sequestration in the subsurface formation.
BRIEF DESCRIPTION OF THE DRAWINGS
[0045] The preferred and alternative embodiments of the present
invention are described in detail below with reference to the
following drawings.
[0046] FIG. 1 is a schematic representation of a generic system
that embodies the invention.
[0047] FIG. 2 is a schematic representation of a more specific
embodiment of the invention.
[0048] FIG. 3 is a schematic representation of a magnified view of
a melting natural gas hydrate formation in a subterranean
location.
[0049] FIG. 4A is a phase diagram where the composition of the
injectant in an arctic-permafrost well bore is 100 mole % carbon
dioxide. The diagram displays the resultant phases.
[0050] FIG. 4B is a phase diagram where the composition of the
injectant in an arctic-permafrost well bore is 50 mole % carbon
dioxide and 50 mole % methane. The diagram displays the resultant
phases.
[0051] FIG. 4C is a phase diagram where the composition of the
injectant in an arctic-permafrost well bore is 10 mole % carbon
dioxide and 90 mole % methane. The diagram displays the resultant
phases.
[0052] FIG. 4D is a phase diagram where the composition of the
injectant in a continental shelf well bore is 100 mole % carbon
dioxide. The diagram displays the resultant phases.
[0053] FIG. 4E is a phase diagram where the composition of the
injectant in a continental shelf well bore is 50 mole % carbon
dioxide and 50 mole % methane. The diagram displays the resultant
phases.
[0054] FIG. 4F is a phase diagram where the composition of the
injectant in a continental shelf well bore is 10 mole % carbon
dioxide and 90 mole % methane. The diagram displays the resultant
phases.
[0055] FIG. 5A is a phase diagram showing the phase relationships
that exist for an injectant (containing only about 13 mole % carbon
dioxide) formed directly from the Prudhoe Bay Unit gas cap. Thus,
FIG. 5A is a phase diagram where the composition of the injectant
is 75.02 mole % methane, 7.95 mole % ethane, 3.99 mole % propane,
and 13.04 mole % carbon dioxide. This is the natural composition of
the gas cap that exists in the Prudhoe Bay Unit.
[0056] FIG. 5B is a phase diagram where the composition of the
injectant is 43.13 mole % methane, 4.57 mole % ethane, 2.29 mole %
propane, and 50.00 mole % carbon dioxide. This is the Prudhoe Bay
Unit gas cap composition with sufficient added carbon dioxide to
increase the carbon dioxide content to 50.00 mole %.
DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENT
[0057] One goal of this invention is to provide a process for
producing natural gas that combines a method of production of
natural gas from hydrates and a method of sequestration of carbon
dioxide in a subsurface location. Currently the need to remove
greenhouse gases from the atmosphere has been emphasized in the
Kyoto Protocol and in the United States by the Clear Skies
Initiative by U.S. President George W. Bush.
[0058] There are many valid reasons for reducing carbon dioxide in
the environment. Also, it can be readily seen that carbon dioxide
present in a methane-rich natural gas acts as a diluent which
contributes no energy and increases the volume of the gas which
must be handled or processed. This in turn leads to increase in
size and cost of the equipment in the plant utilizing the natural
gas and in the cost of development of the pipeline. The carbon
dioxide reduces the heat value of natural gas.
[0059] Hydrates are a major clean hydrocarbon resource. No
production exists from this resource because of the economics
associated with production. Hydrates require energy to be produced
because of the need to dissociate methane from the solid
crystalline structure of the methane hydrate. Net energy production
is possible from hydrates. At least {fraction (1/10)} of the
methane from hydrates is expected to be used in the energy
requirements for the dissociation and subsequent production.
Because of the energy requirements for production, the costs were
non-competitive before the present invention.
[0060] Costs for production of natural gas are affected by the
requirements for removal of carbon dioxide. In natural gas, the BTU
value of the gas is reduced by the presence of carbon dioxide. For
example, a natural gas reservoir may contain, for example, 12 vol.
% carbon dioxide. Several technologies exist for removal of the
carbon dioxide from the natural gas before shipment. Often in the
past, the carbon dioxide that was removed was vented to the
atmosphere. Cost estimates for removal of carbon dioxide from
natural gas is in the range of $50 per ton of carbon.
[0061] Current U.S. Department of Energy (DOE) cost estimates,
cited by H. Herzog et al., CO.sub.2 Sequestration: Opportunities
and Challenges, Massachusetts Institute of Technology, Cambridge,
Mass. (1999), suggest the removal of carbon dioxide from power
plants has a cost range of $66 to $282 per ton of carbon depending
on the specific type of power plant. Future power plants may reduce
these costs to $10 per ton of carbon. New fuel cell technology may
even further reduce the cost. These current costs of carbon dioxide
capture add 1 to 3 cents per kWhr to the electricity cost of base
plants. These energy penalties range from 13 to 37 percent
depending on the power plant type. Current capture technologies can
remove 75 to 90 percent of the carbon dioxide emitted from the
combustion of fossil fuels. Once the carbon dioxide is removed, the
question is where to sequester it.
[0062] The current capture technologies as applied to carbon
dioxide disposal in the practice of injecting carbon dioxide into
oil wells to enhance recovery are mature and are used to provide
information on costs of carbon dioxide disposal. However, storage
of the carbon dioxide for long periods of time has not been
evaluated. Because of industry carbon taxes or credits, future gas
industry production is expected to focus on commercial capture of
carbon dioxide.
[0063] In the present invention, the recovery of natural gas from
hydrates focuses on the moderate to low clay content clastics that
bear hydrates in subterranean formations, either in an
arctic-permafrost location or in a marine continental shelf
location, where the hydrates are a solid phase in pores of
sufficient size such that after hydrate and ice dissociation, the
pore system provides permeability of sufficient extent for
convective and conductive heat transfer and/or depressurization of
the in-place hydrate and production of the resultant gas in a
timely manner. (The resultant gas may not be 100% methane, but may
contain other gases such as carbon dioxide.) Thus, it should be
understood that the present invention is a process that can use
either thermal methods or depressurization, or both thermal methods
and depressurization.
[0064] It should also be noted that the solid phase of natural gas
hydrates in the pores in the subsurface containment subsystem
allows a dynamic pressure seal that changes location with time as
hydrate is melted and then along with a sealing shale layer above
the hydrate zone forms a dynamic containment system which allows
the injectant in the hydrate zone to remain in the liquid phase.
Production of the hydrate-dissociated gas allows little mixing with
the injectant and the injectant to retain its liquid phase.
The Generic System Shown in FIG. 1
[0065] A generic system that embodies the present invention is
illustrated by the system 10 shown in FIG. 1 which includes several
subsystems: (a) a gas/injectant supply subsystem 12 that provides
the gas/injectant; (b) a well subsystem 52 that connects the
gas/injectant supply subsystem to the in-place subterranean source
of natural gas hydrates and that pipes the gas produced up to the
surface; (c) a subsurface containment subsystem 66 that provides
gravity/density segregation of the liquid injectant which contains
carbon dioxide, dissociation of the in-place methane hydrate,
production of gas, and recycling of the injectant/gas provided by
well subsystem 52 from gas supply subsystem 12; and, (d) a control
and monitoring subsystem 77 that provides monitoring and control of
the pressure, temperature, and composition and flow of the
injectant gas and the produced gases.
Gas/Injectant Supply Subsystem
[0066] The gas/injectant supply subsystem 12 in FIG. 1 employs one
or more possible sources of the gas 34 used for the injectant 56.
For example, source 24 is a natural gas accumulation. Another
example is source 26 which is the exhaust of a fossil fuel power
generation plant. Another example is source 28 which is the exhaust
of a fossil fuel compressor plant. Another example is source 30
which is the exhaust from a gas-to-liquids plant.
[0067] The injectant 56 is more efficient for heat transfer if the
injectant is a liquid at the zone where it is being injected. More
importantly, if the injectant is a liquid it allows gravity/density
separation of the liquid carbon dioxide injectant from the
hydrate-evolved natural gas.
[0068] FIGS. 4A-F are pressure and temperature diagrams that
show:
[0069] 1. The phase diagram and envelope (lines 260, 312, 360, 408,
460, and 512) of an injectant where the injectant is of the
specified composition, the phases of the injectant that have a
liquid phase or critical phase and are shaded for three conditions
where methane vapor exists:
[0070] (a) The liquid and vapor phase of the injectant co-exist and
the injectant has a density greater than the vapor released upon
dissociation of the hydrate (areas 300 and 504);
[0071] (b) The liquid phase of the injectant exists (that is, there
is no vapor phase of the injectant) or the critical phase of the
injectant exists and the injectant has a density greater than the
vapor released upon dissociation of the hydrate and the pressure is
below the fracture pressure gradient (areas 252, 302, 402, 452, and
502); and
[0072] (c) The pressure is above the fracture pressure gradient
(areas 250, 304, 348, 400, 450, and 500).
[0073] 2. The phase envelope (lines 258, 310, 358, 410, 458, and
510) for 100% methane. For this phase envelope, the hydrate phase
is in the higher pressure and lower temperature region and the
vapor phase is in either the lower pressure or higher temperature
regions. The typical composition of an in-place hydrate is near
100% methane.
[0074] 3. The specific pressure and temperature profile of a well
(lines 256, 308, 356, 406, 456, and 508) within the area of hydrate
occurrence. This is the pressure and temperature profile for each
well. The intersection of the well bore pressure and temperature
gradient (lines 256, 308, 356, 406, 456, and 508) with the methane
phase envelope (lines 258, 310, 358, 410, 458, and 512) shows where
the in-place hydrates are stable and can exist in the subsurface
location.
[0075] 4. The fracture gradient for the well (lines 254, 306, 354,
404, 454, and 506) is the injection pressure which, if exceeded,
will fracture the formation. The fracture pressure of a well, where
hydrates are stable, depends upon the depth of the hydrates. The
maximum fracture pressure is based upon the maximum depth of the
hydrate occurrence. Fractures can breach the subsurface containment
and cause pressure leakoff. Vertical fractures can leak off to low
pressure zones. Whether vertical fractures occur is dependent on
local stress conditions or perhaps other unknown factors.
Horizontal fractures may even help the production process.
[0076] 5. The ocean floor (lines 412, 462, and 514).
[0077] For the pressure and temperature profiles for the
arctic-permafrost setting, a pressure gradient of 0.421 psi/ft and
a fracture gradient of 0.695 psi/ft was used. For the pressure
gradient for the marine-continental shelf setting, a pressure
gradient of 0.45 psi/ft and a fracture gradient of 0.695 psi/ft
were used. Temperature gradients were taken from T. S. Collett et
al., "Natural Gas Hydrates", SPE-AAPG Western Region Meeting, May
23, 2002, Anchorage, Ak. Fracture gradients, well bore pressures,
and temperature gradients are dependent on the conditions specific
to the location of the well.
[0078] It should be noted that if the injectant is above the
critical point, the injectant is a single phase. For pure carbon
dioxide, a temperature of 87.87.degree. F., a pressure of 1071
psia, and a volume 0.0342 cu ft/lbm is the critical point (see
Robert S. Metcalf, Petroleum Engineer's Handbook, Table 20.2 Some
Physical Constants of Hydrocarbons). (The unit "lbm" refers to
pounds of mass.)
[0079] At conditions such as these, the injectant has the
characteristics of a single phase. This critical phase can be used
as a liquid injectant if the density is greater than the vapor
released from the hydrate at subsurface conditions. Phase and
density data specific to the injectant and to the in-place hydrate
composition where this invention is to be used should be obtained
from laboratory analyses to ensure that the appropriate
relationships between pressure, temperature, and density for the
injectant are used in the inventive system.
[0080] FIGS. 4A-F display several injectant compositions
(containing different amounts of CO.sub.2 and methane) where the
injectant 56 contains at least some carbon dioxide. The shaded
areas that are designated as shaded areas 250 and 252 in FIG. 4A;
shaded areas 300, 302, and 304 in FIG. 4B; shaded areas 348, in
FIG. 4C; shaded areas 400 and 402 in FIG. 4D; shaded areas 450 and
452 in FIG. 4E; and shaded areas 500, 502, and 504 in FIG. 4F show
the pressures and temperatures where the liquid phase or critical
phase of the injectant 56 is stable and the vapor phase of the
hydrate 100 (in FIG. 1) is stable and the injectant at subsurface
conditions has a density greater than the density of the vapor
phase released by the dissociation of the hydrate. The injectant 56
needs to be a liquid and to be denser than the vapor phase released
during hydrate dissociation for the desired gravity/density
partitioning to take place.
[0081] The optimal pressures and temperatures are designated as
shaded area 252 in FIG. 4A, shaded area 302 in FIG. 4B, shaded area
402 in FIG. 4D, shaded area 452 in FIG. 4E, and shaded area 502 in
FIG. 4F.
[0082] The effects of injection pressure on formation fracturing in
the subsurface containment subsystem will need to be evaluated on
an individual well basis. The stability zone for hydrate occurrence
and its exact pressure profile in the subsurface along with the
pressure range under which fracturing will occur in the orientation
of the fractures in this zone and its effects on the injection
containment may further constrain the range of optimal pressure and
temperature of the injectant. The shaded areas designated as shaded
area 304 in FIG. 4B, shaded area 348 in FIG. 4C, shaded area 400 in
FIG. 4D, shaded area 450 in FIG. 4E, and shaded area 500 in FIG. 4F
are at pressures that are above the fracture pressure of the rock
formation containing the hydrate as well as the fracture pressure
of the overlying shale. Injection at pressures greater than the
fracture pressure can breach the subsurface containment. The stress
fields at the time of injection are critical to the orientation of
the fracture (vertical or horizontal). A horizontal fracture does
not pose a problem. A vertical fracture that fractures the
overlying shale may be a problem because of the migration of gas
along that fracture and potential subsequent breach of containment
and depressurization of injectant.
[0083] The shaded areas designated as area 300 in FIG. 4B and area
504 in FIG. 4F are not effective at partitioning the evolved
natural gas from the hydrate because of the injectant vapor which
is present in these pressure and temperature ranges.
[0084] In FIG. 1, source 24 is a natural gas accumulation (that is
typically not from a hydrate source) that supplies produced gases
16 to conduit 14. Because this source of gas may not contain enough
carbon dioxide to form a liquid injectant at subsurface conditions,
additional carbon dioxide may be added to injectant 56 to ensure
this. This additional carbon dioxide is added during gas
conditioning in module 36.
[0085] In many areas, a natural gas accumulation rich in carbon
dioxide exists at deeper depths than where the methane rich
hydrates exist. An example of this source 24 is the natural gas
accumulation in the Prudhoe Bay Reservoir, Alaska, where the
natural gas accumulation is beneath the hydrate zone known as the
Eileen Hydrate Accumulation. This natural gas accumulation is
called the Prudhoe Bay Unit (PBU) gas cap and it contains
approximately 13 mole % carbon dioxide. Thus, the supply of carbon
dioxide for source 24 in subsystem 12 could come directly from a
well connected to a deeper gas source and carbon dioxide from the
deeper gas source could be produced to the surface and then be
injected into the hydrate zone. Additional carbon dioxide will be
required to be added to the gas from the natural gas source so that
its composition as an injectant is liquid at the pressure and
temperature for the production of the hydrate. Carbon dioxide
removed from the gas cap by gas processing can be used for
injection or it can be mixed with the gas cap gas to form a gas of
suitable composition for an injectant.
[0086] Source 26 is a fossil fuel electric power generation plant
which produces exhaust gas 18 containing carbon dioxide from the
engine of the generation plant. Source 28 is a fossil fuel
compressor plant which produces exhaust gas 20 containing carbon
dioxide from the engine of the compressor plant. Current engine
technologies produce exhaust gases containing from 3-12 volume %
carbon dioxide and significantly more NO.sub.x. Power plant
technologies currently being developed, such as solid oxide fuel
cells and molten carbonate fuel cells, reduce the NO.sub.x
emissions and provide a flue gas primarily composed of carbon
dioxide. Thus, solid oxide fuel cells and molten carbonate fuel
cells are possible sources of injectant 34. This gas may need
minimal gas handling or compositional modification before being
supplied for injection.
[0087] Current NO.sub.x production from a power or compressor plant
can be injected into hydrates as a hot gas, but not as a liquid.
The cost of removing NO.sub.x from flue gas drives up the cost of
production and may make the process too expensive. Utilizing the
injectant as a liquid, so that density/gravity segregation occurs,
is the preferred mode of operating the present invention. Thus, the
gas/injectant stream 34 should be a liquid injectant, containing at
least some carbon dioxide, that is injected into the subsurface
containment subsystem 66.
[0088] Exhaust gas 22 is from natural gas-to-liquids plant source
30. The exhaust gas contains some carbon dioxide. This carbon
dioxide would be used in the gas source 34 and may require
processing in module 36.
[0089] Thus, the gas/injectant stream 34 should form a liquid
injectant, containing at least some carbon dioxide, that is
injected into the subsurface containment subsystem 66. The
injectants with the higher carbon dioxide content allow a broader
range of options for using the injectant. If the content of carbon
dioxide is high enough, as in FIGS. 4A and 4B, the injectant can be
liquid at a pressure and temperature range below the well bore
stability of hydrate. This allows depressurization to be utilized
for the production of the hydrate evolved gas.
[0090] The gas/source 34 is pumped through conduit 14 in FIG. 1. In
the case of source 24, where the gas supply (a natural gas
reservoir) is underneath the hydrate accumulation, the well
injection casing string may be the conduit. Otherwise, conduit 14
will be on the surface supplying the exhaust gases or produced
gases to initial gas processing module 36. The gas processing
module 36 performs gas processing functions such as expansion or
compression, temperature control, water removal, and/or composition
adjustment using conventional technology.
[0091] The gas storage module 38 in FIG. 1 is located before the
final gas processing injection module 40. The gas storage module 38
is either (a) a tank on the surface; or (b) a reservoir that is the
source of the subsurface natural gas accumulation used in source
24. The final gas processing module 40 provides temperature and
pressure control prior to injection and includes gas compressors,
gas pumps, gas expansion chambers, gas heaters and/or heat
exchangers.
[0092] On the upstream side of FIG. 1, produced gas processing
module 42 is on the surface and separates the produced gases, such
as methane and carbon dioxide so that additional removed carbon
dioxide 44 can be sent to storage module 38 to be injected, and/or
methane can be removed prior to further gas processing and
distribution at the production facility 48. Some of the methane 32
from production facility 48 flows through pipe 76 as needed to fuel
the power generation plant 26, to fuel the compressor plant 28,
and/or to supply the gas-to-liquids plant 30. The remaining methane
from production facility 48 is transported through pipe 96 to a
natural gas distribution system. Gas processing modules 36, 40, and
42 may be part of the production facility 48 and may contain common
elements.
Well Subsystem
[0093] The well subsystem 52 includes the injection pipe string 54,
the production pipe string 58, a larger well bore 60, injection
packer 62, and production packer 64. The well subsystem can consist
of one or multiple wells.
[0094] The final injectant 56 flows down the injection pipe string
54 and is discharged where the natural gas hydrates are located.
The natural gas 94 which is released from the hydrates flows up the
production pipe string 58 to the gas processing module 42.
[0095] The well subsystem 52 is created by drilling and completing
at least one well in a subterranean formation where there is at
least some natural gas in the form of hydrate. The site is chosen
where the geologic formation and hydrate occurrence allows for a
subsurface containment subsystem 66.
[0096] FIG. 1 shows the larger well bore 60 which can be lined with
conventional casing or not as desired and which is drilled into a
subterranean formation so that well bore 60 penetrates a zone of
hydrate. Various effects need to be considered in the design of the
well, for example, effects such as: (a) melting of the surrounding
well bore hydrate and/or ice/permafrost by heat transfer from the
injectant or casing-cement heat of formation; (b) casing strain and
stress effects via changes in pore pressure because of different
subterranean rock properties affecting ice or hydrate stability;
and, (c) the formation of hydrates in the production and injection
strings, especially in times of shut down. The well should include
the necessary precautions to remedy these effects. These remedies
include insulated tubing and casing, hydrate formation prevention
techniques such as heating using heat tape, hydrate inhibitors,
cement selection, and selection of slip joints as are conventional
in the industry.
[0097] Boreholes are drilled at the desired distances and
patterning from the surface into the subterranean formation.
Thereafter the casing and pipe strings are set into the formation
to the desired depth. Perforated or slotted casing is employed at
the lower end of well bore 60 as shown in FIG. 1. The injection
string 54 is placed so that injection occurs at greater pressure
and is placed deeper than the production string. The system is
designed to promote circulation between the injection and
production string so that convective and conductive heat transfer
and depressurization are optimized. The system may be employed in a
horizontal well so long as the injection string is located so that
the natural gas migrates into the production string via pressure
differences. Since the system relies on gravity segregation, the
injection string should penetrate deeper than the production
string.
Subsurface Containment Subsystem
[0098] The subsurface containment subsystem 66 in FIG. 1 is
illustrated in a three-dimensional schematic representation. It
includes natural geologic containment structure 68 comprised of a
layer of shale 98 and the in-situ solid (unmelted) natural gas
hydrates 100. The size of the zone where the hydrates have melted
within geologic containment structure 68 will increase over time.
It should be understood that the clastic grains still remain in the
zone where the hydrates have melted. For example, at time T1 the
zone within the geologic containment structure will be of size 70;
at time T2 the zone within the geologic containment structure will
be of size 72; and at time T3 the zone within the geologic
containment structure will be of size 74. Thus, this dynamic
containment structure 68 will be defined through time by subsurface
and injection conditions as the hydrate dissociation increases with
time.
[0099] Injection packer 64 is placed in the lower portion of well
bore 60 to block injectant 56 from production string 58. Production
packer 62 is placed higher in well bore 60 to block production gas
94 from going up inside well bore 60 and to insure that production
gas 94 goes up production pipe string 58. In a typical well,
drilling will go through a layer of shale 98 which will function as
the ultimate top of the subsurface containment subsystem 66. The
containment shale 98 provides a vertical seal for the produced gas
evolved from the hydrates underlying the containment shale.
[0100] Thus, the selection of the formation of the subsurface
containment system is critical. It is selected so that an overlying
lithologic-permeability barrier isolates the hydrate zone below and
so that the permeability barrier will not be significantly affected
by melting of the hydrate. The overlying lithologic-permeability
barrier should be of sufficient lateral and vertical extent to
allow the gas/liquid circulation system to operate and the pressure
and temperature to be maintained for the liquid injectant.
[0101] Dissociation of the natural gas hydrate occurs by
emplacement of the injectant 56 within the subsurface containment
subsystem 66 by using heat transfer from the injectant, pressure
change by pressure draw down on the production string, and by the
rate of dissociation of natural gas hydrate to allow the natural
gas-hydrate to dissociate to free natural gas and to migrate to the
production string 58. The methane hydrate dissociates to water and
methane in a ratio of about 8:1.
[0102] If the injectant 56 is injected at a high enough pressure,
fractures in the subsurface rock formation will occur. The shaded
areas designated as area 250 in FIG. 4A, area 304 in FIG. 4B, area
348 in FIG. 4C, area 400 in FIG. 4D, area 450 in FIG. 4E, and area
500 in FIG. 4F are at pressures that are above the fracture
pressure of the rock, which will possibly result in breaching the
subsurface containment. The effects of injection pressure on the
formation fracturing on the subsurface containment will need to be
evaluated on an individual well basis. The stability zone for
hydrate occurrence and its exact pressure profile in the
subsurface, along with the pressure range under which fracturing
will occur such that it affects subsurface containment in this
zone, may further constrain these optimal pressure and temperature
regions.
[0103] If the principal stress fields and other unknown factors are
such that these fractures are parallel to the bedding and to the
containment shale barrier at the top of the interval, there may not
be a problem with breaching the subsurface containment subsystem.
However no matter what the type of fracture, vertical or horizontal
(or parallel to the bedding), the injectant should not be injected
at a high enough pressure to cause the subsurface containment
system to be breached by a fracture that would cause insufficient
pressure retention in the subsurface containment subsystem for the
injectant to exist as a liquid phase. For example, if the injectant
56 or the hydrate-evolved natural gas 94 exhibits pressure leak-off
because a vertical fracture penetrated the sealing shale at the top
of the subsurface containment subsystem, then the injectant may
depressurize and become vapor or the vapor phase derived from the
hydrate will not reach the production string because of gas
migration along the fractures.
[0104] A free gas zone often exists below a stable hydrate zone.
Emplacement of the injectant in this zone may not be possible
because dynamic subsurface containment cannot be maintained.
Increasing the pressure in this zone is dependent on the size of
the aquifer underlying the free gas zone and chances are that the
zone will be limited to pressure increase. If this free gas zone is
encountered, it is recommended to produce the gas to the surface by
decreasing pressure and to depressurize the well so that hydrate
production occurs. Care should be taken that the injectant remains
a liquid at these reduced pressures.
[0105] If the injectant can be injected at a lower pressure, the
injectant can be injected at and sequestered at the narrow pressure
and temperature range that exists between the injectant phase
envelope and the hydrate phase envelope. In FIG. 4A, for example,
the carbon dioxide will form a hydrate and methane from the hydrate
will be in a vapor phase. This will allow continued production of
methane while carbon dioxide is at the range of temperature and
pressure where it can form a solid hydrate.
[0106] As discussed above, the narrow range of temperature and
pressures that define the difference between the injectant phase
envelope and the methane phase envelope could be used as a range of
temperature and pressure in the subsurface to abandon the well. The
temperature and pressure of the subsurface can be controlled by the
rate of injection and the temperature of injection, regional
temperature gradient, the rate of dissociation, phase transition
temperature changes, and by pressure drawdown in the production
string. At this range of temperature and pressure between, for
example, lines 260 and 258 in FIG. 4A before they cross over, the
injectants, especially those with higher carbon dioxide content,
would be in the hydrate stability zone while the methane at this
temperature and pressure is a vapor.
Control and Monitoring Subsystem
[0107] The gases and liquids in system 10 in FIG. 1 are controlled
and monitored by a control and monitoring subsystem. The control
and monitoring subsystem includes flow control devices 78, 80, 82,
and 84 that control the pressure (of the injectant and the produced
gas) by means of valves, pumps, compressors, and/or expanders that
control the temperature (of the injectant and the produced gas) by
means of heaters, heat exchangers, and/or heat tape. Some of these
devices, such as compressors, expanders, heaters or heat
exchangers, may be part of the gas/injectant supply subsystem. The
control and monitoring subsystem also includes sensing devices 86,
88, 90, and 92 that monitor pressure and temperature in the gas
supply subsystem, the well subsystem for injection and production,
and the subsurface containment subsystem. Conventional gauges (for
example, either electrical or fiber optic) are used. The placement
of these devices is such as to adequately monitor the production
and injection strings in both the subsurface containment subsystem
and elsewhere, such as in the gas processing modules 36, 40, 42 and
48. The injectant/gas circulation system is controlled and
monitored to allow the initiation, the continuation, and the
shutdown of circulation of an injectant and produced gasses. It is
also utilized to optimize the rates of production of the gas and
the rate of injection and the temperature of the injectant.
The Embodiment Shown in FIG. 2
[0108] A more specific subsurface embodiment of the present
invention is illustrated by the system 110 shown in FIG. 2. System
110 includes several subsystems: a gas/injectant supply subsystem
112 that provides the gas/injectant; a well subsystem 114 that
connects the gas/injectant supply subsystem to the in-place
subterranean source of natural gas hydrates and that pipes the gas
produced up to the surface; a subsurface containment subsystem 116
that provides gravity/density segregation of the liquid injectant
which contains carbon dioxide, dissociation of the in-place methane
hydrate, production of gas, and recycling of the injectant/gas
provided by well subsystem 114 from gas/injectant supply subsystem
112; and, a control and monitoring subsystem that provides
monitoring and control of the pressure, temperature, and
composition and flow of the injectant and the produced gases.
Gas/Injectant Supply Subsystem
[0109] The gas/injectant supply subsystem 112 in FIG. 2 employs one
or more possible sources of gas for the injectant 118. For example,
source 144 is a natural gas accumulation. Another example is
exhaust 146 from a fossil fuel power generation plant 152. Another
example is exhaust 148 from a fossil fuel compressor plant 154.
[0110] The gas from the above sources is compressed by compressor
150 into gas storage tank 120. The injectant 118 used for melting
the hydrate is more efficient for heat transfer if the injectant is
liquid at the zone where it is being injected; also more
importantly if the injectant is liquid it allows for
gravity/density separation of the liquid carbon dioxide injectant
from the hydrate-evolved natural gas. Thus, the gas/injectant
stream 118 is a liquid that is injected into the subsurface
containment subsystem 116.
[0111] FIGS. 4A-F display several injectant compositions
(containing different amounts of CO.sub.2 and methane) where the
injectant 118 contains at least some carbon dioxide. The shaded
areas that are designated as shaded areas 250 and 252 in FIG. 4A;
shaded areas 300, 302, and 304 in FIG. 4B; shaded areas 348 in FIG.
4C; shaded areas 400 and 402 in FIG. 4D; shaded areas 450 and 452
in FIG. 4E; and shaded areas 500, 502, and 504 in FIG. 4F show the
pressures and temperatures where the liquid phase or critical phase
of the injectant 118 is stable and the vapor phase of the hydrate
172 is stable and the injectant at subsurface conditions has a
density greater than the density of the vapor phase released by the
dissociation of the hydrate. The injectant 118 needs to be a liquid
and to be denser than the vapor phase released during hydrate
dissociation for the desired gravity/density partitioning to take
place.
[0112] The optimal pressures and temperatures are designated as
shaded area 252 in FIG. 4A, shaded area 302 in FIG. 4B, shaded area
402 in FIG. 4D, shaded area 452 in FIG. 4E, and shaded area 502 in
FIG. 4F.
[0113] The effects of injection pressure on formation fracturing in
the subsurface containment subsystem will need to be evaluated on
an individual well basis. The stability zone for hydrate occurrence
and its exact pressure profile in the subsurface along with the
pressure range under which fracturing will occur in the orientation
of the fractures in this zone and its effects on the injection
containment may further constrain the range of optimal pressure and
temperature of the injectant. The shaded areas designated as shaded
area 250 in FIG. 4A, as shaded area 304 in FIG. 4B, shaded area 348
in FIG. 4C, shaded area 400 in FIG. 4D, shaded area 450 in FIG. 4E,
and shaded area 500 in FIG. 4F are at pressures that are above the
fracture pressure of the rock formation containing the hydrate as
well as the fracture pressure of the overlying shale. Injection at
pressures greater than the fracture pressure can breach the
subsurface containment. The stress fields at the time of injection
are one factor critical to the orientation of the fracture
(vertical or horizontal). A horizontal fracture does not pose a
problem. A vertical fracture that fractures the overlying shale or
subsurface containment may be a problem because of the migration of
gas along that fracture and potential subsequent breach of
containment and depressurization of injectant.
[0114] The shaded areas designated as area 300 in FIG. 4B and area
504 in FIG. 4F are not effective at partitioning the evolved
natural gas from the hydrate because of the injectant vapor which
is present in these pressure and temperature ranges.
[0115] The gas processing module 124 in FIG. 2 performs gas
processing functions such as expansion or compression, temperature
control, water removal, and/or composition adjustment as is
available from conventional technology of the industry. The
gas/injectant 118 is then pumped down through conduit 122 in FIG.
2.
[0116] Produced gas processing module 126 is on the surface and
separates the components in the produced gas 136, such as methane
and carbon dioxide, and removes water prior to sending the methane
component 128 through pipe 130 to the production facility 132 and
prior to re-circulating the carbon dioxide component 134 through
pipe 142 to gas storage tank 120. Methane 138 from production
facility 132 flows through pipe 140, as needed, to power generation
plant 152 or to compressor plant 154. Gas processing modules 124,
126, and 150 may be part of the production facility or central
compressor plant 132 and may contain common elements.
Well Subsystem
[0117] The well subsystem 114 includes the injection pipe string
122, the production pipe string 156, the larger well bore 158,
injection packer 160, and production packer 162.
[0118] As explained above, the final injectant 118 flowing down the
injection pipe string 122 can come from one or more possible
sources 144, 146, and 148. The production pipe string 156
transports production gas 136 to the gas processing module 126.
[0119] The well subsystem is created by drilling and completing at
least one well in a subterranean formation where there is at least
some natural gas in the form of hydrate and the conditions are
chosen where the formation and hydrate occurrence allows for a
subsurface containment system.
[0120] FIG. 2 shows the well bore 158 lined with conventional
casing 164 which has been drilled in a subterranean formation in a
pressure and temperature region so that well bore 158 penetrates a
zone of hydrate. Cement 166 has been placed around the exterior of
casing 164. The following effects need to be considered in the
design of the well: (a) melting of the surrounding well bore
hydrate and/or ice/permafrost by heat transfer from the injectant
or casing cement heat of formation; (b) casing strain and stress
effects via changes in pore pressure because of different
subterranean rock properties effecting ice or hydrate stability;
and, (c) the formation of hydrates in the production and injection
strings especially in times of shut down. The well should include
the necessary precautions to remedy these effects. These remedies
include insulated piping and casing, hydrate formation prevention
techniques, hydrate inhibitors, heat tape, cement selection, and
selection of slip joints as is available from conventional
technology of the industry.
[0121] Boreholes are drilled at the desired distances and
patterning from the surface into the subterranean formation.
Thereafter the casing, cement, and piping are set into the
formation to the desired depth. As shown in FIG. 2, the lower
portion of casing 164 and cement 166 are perforated or slotted over
the zone of interest in the hydrate. The injection string is to be
placed so that injection occurs at greater pressure and is placed
deeper than the production string, production so that gravity
segregation can occur. The completion is designed to promote
injectant emplacement so that it is at the bottom of the well while
dissociation of hydrate 172 can continue from heat transfer from
the injectant and from depressurization from the production string
156, so that convective and conductive heat transfer and
depressurization are optimized. The system may be employed in a
horizontal well so long as the injection string is located so that
the natural gas migrates into the production string via pressure
differences. Since the system relies on gravity segregation, the
injection string should penetrate deeper than the production
string.
Subsurface Containment Subsystem
[0122] The subsurface containment subsystem 116 in FIG. 2 includes
natural geologic containment structure 168 comprised of a layer of
shale 170 and the in-situ solid (unmelted) natural gas hydrates
172. The size of the zone (created by the dissociation of the
hydrates) within geologic containment structure 168 will increase
over time. For example, at time T1 the zone within the geologic
containment structure will be of size 174; at time T2 the zone
within the geologic containment structure will be of size 176; and
at time T3 the zone within the geologic containment structure will
be of size 178. Thus, this dynamic containment structure 168 will
be defined through time by subsurface and injection conditions as
the hydrate dissociation increases with time.
[0123] Injection packer 160 is placed in well bore 158 to block
injectant 118 from production string 156. Production packer 162 is
placed higher in well bore 158 to block production gas 136 from
going up inside well bore 158 and to insure that production gas 136
goes up production pipe string 156. The layer of shale 170
functions as the top of the subsurface containment subsystem 116.
The containment shale 170 provides a vertical seal for the produced
gas evolved from the hydrates underlying the containment shale.
[0124] The selection of the formation of the subsurface containment
system is critical. It is selected so that an overlying
lithologic-permeability barrier isolates the hydrate zone below and
so that the permeability barrier will not be significantly affected
by melting of the hydrate. The overlying lithologic-permeability
barrier should be of sufficient lateral and vertical extent to
allow the gas/liquid circulation system to operate and the pressure
and temperature to be maintained for the liquid injectant.
[0125] Dissociation of the natural gas hydrate occurs by
circulating the injectant 118 within the subsurface containment
subsystem 116 by using heat transfer from the injectant, pressure
change, and rate of dissociation of natural gas hydrate to allow
the natural gas hydrate to dissociate to free natural gas and to
migrate to the production string 156. The natural gas hydrate
dissociates to water and methane, respectively, in a ratio of about
8:1.
[0126] If the injectant 118 is injected at a high enough pressure,
fractures in the subsurface rock formation will occur. The shaded
areas designated as area 250 in FIG. 4A, area 304 in FIG. 4B, area
348 in FIG. 4C, area 400 in FIG. 4D, area 450 in FIG. 4E, and area
500 in FIG. 4F are at pressures that are above the fracture
pressure of the rock, which will possibly result in breaching the
subsurface containment.
[0127] The effects of injection pressure on the formation
fracturing on the subsurface containment will need to be evaluated
on an individual well basis. The stability zone for hydrate
occurrence and its exact pressure profile in the subsurface, along
with the pressure range under which fracturing will occur such that
it affects subsurface containment in this zone, may further
constrain these optimal pressure and temperature regions.
[0128] If the principal stress fields or perhaps other unknown
factors are such that these fractures are parallel to the bedding
and to the containment shale barrier at the top of the interval,
there should not be a problem with vertically breaching the
subsurface containment subsystem via fracture. However no matter
what the type of fracture, vertical or horizontal, the injectant
should not be injected at a high enough pressure to cause the
subsurface containment system to be breached by a fracture that
would cause insufficient pressure retention in the subsurface
containment subsystem for the injectant to exist as a liquid phase.
For example, if the injectant 118 or the hydrate-evolved natural
gas 136 exhibits pressure leak-off because a vertical fracture
penetrated the sealing shale at the top of the subsurface
containment subsystem, then the injectant may depressurize and
become vapor.
Control and Monitoring Subsystem
[0129] The gases and liquids in system 110 in FIG. 2 are controlled
and monitored by a control and monitoring subsystem. The control
and monitoring subsystem includes flow control devices 184, 186,
188, and 190 that control the pressure by means of pumps,
compressors, and/or expanders and that control the temperature by
means of heaters, heat exchangers, and/or heat tape. The control
and monitoring subsystem for the subsurface includes sensing
devices 192, 194, and 196 that monitor pressure and temperature in
the gas/injectant supply subsystem, the well subsystem for
injection and production, and the subsurface containment subsystem.
Conventional gauges (for example, either electrical or fiber optic)
are used. The gas circulation system is controlled and monitored to
allow the initiation, the continuation, and the shutdown of
circulation of gases for injection and production.
Permeability of the Pore System
[0130] Permeability of the pore system with hydrate and dissociated
hydrate are critical to setting up circulation of the injectant
stream. The injectant circulation stream transfers heat by
conduction and convection. The hydrate will be dissociated by this
heat in addition to depressurization. By convection the circulation
of the injectant stream can better dissociate the hydrate. FIG. 3
is a magnified schematic representation of the pore system 210 in
its relationship to permeability with evolution from a solid
hydrate to gas.
[0131] FIG. 3 illustrates the phases in the process of dissociation
that the methane hydrate experiences. In pore system 210, above
boundary 218 is a zone where the frozen hydrate in the pore system
is not yet changed. This zone forms a pressure and permeability
barrier to fluid flow. In conjunction with the overlying shale
barrier, this zone above boundary 218 forms the subsurface
containment subsystems in FIGS. 1 and 2. Boundary 218 is a dynamic
boundary moving with time. At earlier points in time, the boundary
was at location 216, at location 214, and at location 212. It will
be understood that in reality the boundary moves continuously,
rather than by moving in the discrete changes illustrated in FIG.
3.
[0132] In addition to the solid zone residing outside of boundary
218, FIG. 3 also illustrates zones 230, 232, and 234. Zone 230 is a
mixing zone where the liquid injectant mixes with water that has
evolved from the hydrate. In this zone 230, the injectant is
transferring heat by convection and by conduction. The next zone
232 is a hydrate melting zone where the hydrate is in the final
stages of melting. The methane which is released flows upwardly
because of gravity segregation/density differences with the water.
The water which is evolved segregates downwardly. The next zone 234
is a hydrate melting zone where the hydrate is in the early stages
of melting. The methane which is released flows upwardly. The water
which is evolved flows downwardly.
[0133] In the zone above boundary 218 in FIG. 3, clastic grains 220
are surrounded by hydrate filled pores 222. The amount of hydrate
in the pores have been measured to be greater than 80 volume %. The
exact location of the hydrate in pores 222, that is, whether the
hydrate coats grains 220 or is located in the center of the pores,
is not known.
[0134] In hydrate melting zone 234, pores 224 contains partially
dissociated hydrate. As the hydrate dissociates, it releases gas
and water so the remainder of pores 224 consist of water and
methane gas. In hydrate melting zone 232, the evolved and in-place
water in pores 226 separates from the methane gas evolved from the
hydrate. In mixing zone 230, water and the liquid injectant mix in
pores 228. In this zone 230, pores 228 are now devoid of any
hydrate.
[0135] As the hydrate is heated or depressurized, water and methane
gas evolve at an approximate 8 to 1 ratio in the pore system. The
methane gas separates from the water and the density difference
supports the gravity/density separation of the hydrate-evolved
natural gas from the water. The hydrate evolved natural gas is
nearly 100% methane. The methane gas migrates upwardly because of
its significantly lower density compared to water and the liquid
injectant. Because of the 8:1 ratio of water to gas in the melting
of the hydrate, there is expected to be significant retardation of
mixing the hydrate-evolved natural gas and the injectant resulting
in only minor mixing of the evolved natural gas with the injectant.
Some mixing of the carbon dioxide injectant and the methane may
occur, resulting in a mixed natural gas containing methane and
carbon dioxide gas as well as the liquid injectant becoming more
methane rich. As can be seen from the phase diagrams, the more
methane in the injectant the higher the pressure and temperature
required for the liquid phase to exist. Methane is produced before
it is allowed to mix with the injectant.
[0136] In the case where a free gas zone exists below the hydrate,
the initial subsurface containment subsystem can comprise the
container holding the free gas. This free gas zone below the
hydrate should be produced of any natural gas prior to supplying
the hydrate zone with liquid injectant containing in part carbon
dioxide. Maintenance of a higher pressure than the original
pressure in the free gas zone may not be possible, so maintaining a
pressure sufficient for the stability of the liquid injectant may
be difficult in the free gas zone.
[0137] The presence of hydrate can restrict flow to the effect that
hydrate filled pores are an effective permeability barrier and
pressure barrier. Well test results of hydrate zones and
spontaneous potential (SP) electric logs give support to this
notion. Since the hydrate filled pore location changes with time
and with dissociation of the hydrate, there is a dynamic change in
the dissociation zone and in the convective paths possible for
injectant circulation as shown as in FIG. 1 at 70, 72, and 74 which
represent the changes occurring at times T1, T2, and T3,
respectively.
[0138] Field studies and reservoir modeling results suggest that
circulation through a free gas zone that often lies below the base
of hydrate zones should allow convective and conductive recovery of
in-place hydrates. Since free gas zones do not necessarily occur in
all hydrate reservoirs, utilization of completion technology and
well bore technology (such as horizontal wells) are optimized to
set a path of circulation that leads to convective flow of the
injectant. This is done by placing the injector near to the base of
the hydrate zone or in the free gas zone so that convection can
occur as the hydrate dissociates and in the already dissociated
hydrate zones.
[0139] Fracturing of the subsurface structure is a possible way to
enhance the convective circulation of the injectant. This would aid
in developing a good injectant circulation pattern. If vertical
fractures develop, care must be taken not to breach the shale
barrier that forms the upper seal for the subsurface containment
subsystem. Horizontal fractures may be very effective at enhancing
convective circulation; however, horizontal fracturing typically
occurs in areas where the principal stress directions are such that
the vertical principal stress is less than either or both of the
horizontal principal stresses.
[0140] Heat transfer from the circulating injectant is both
convective and conductive and the design of the subsurface
containment subsystem and the well subsystem completions should
optimize convective flow and density segregation of the liberated
methane gas from the liquid phases of injectant based on the choice
of the location of the production and injection strings/wells in
the subsurface.
[0141] The nearer the injectant pressure and temperature is located
on the pressure-temperature diagram to the phase boundary of the
solid in-place hydrate the lower the requirement of heat needed to
melt the hydrate. Higher pressure and temperature for the injectant
increase the costs of the injectant. This should be taken in to
account in design of the temperature and pressure at which
injection occurs.
[0142] FIGS. 4A-F are diagrammatically constructed using the
program CSMHYD.exe developed by E. D. Sloan, Jr. and the trend of
the carbon dioxide vapor and liquid phases of carbon dioxide. The
phase areas shown beyond the phase boundary for hydrate formation
are only diagrammatic displayed and may not represent the true
phase boundary. These phase diagrams are shown for illustration
only and need to be developed from laboratory tests for each
hydrate accumulation and for each injectant. It is recommended that
laboratory tests be performed to confirm the phase boundaries and
density data for the injectant that will be used.
[0143] Injection in the proper pressure and temperature range is
accomplished by the system of monitors and controls. At the end of
useful methane hydrate production, the pressure and temperature of
the production well may be reduced to a temperature and pressure
range that would allow the in-reservoir injectant to form a
hydrate.
[0144] The production natural gas that has circulated to the
production string may be cyclic. The rate at which methane evolves
and segregates is critical to the production cycle. Production from
time to time may be shut in or sent to gas storage so that the
optimal flow of methane rich gases can be sent to the production
facility.
[0145] Gravity/density segregation of the liquid injectant and the
water from the natural gas evolved from the in-place hydrate allows
most of the carbon dioxide in the injectant to remain in the
subsurface. The density-segregated natural gas is produced to the
surface where it is processed in the production facility to further
to remove methane which is distributed to a pipeline or utilized
locally for power production or compression. Any carbon dioxide
removed from the natural gas in the processing facility is cycled
back to the subsurface. Changes in the pressure and temperature of
the injectant and water mixture in the subsurface proceed to
conditions where a clathrate of carbon dioxide is formed in the
subsurface, thus leaving carbon dioxide not only sequestered, but
sequestered as a hydrate.
[0146] The produced natural gas may be further processed before
being supplied to the gas supply subsystem, since the produced
natural gas may contain both methane and carbon dioxide. The
injectant that is retained in the subsurface containment subsystem
as a liquid or hydrate results a decrease of the overall percent of
carbon dioxide vented to the atmosphere and sequestration of carbon
dioxide in the subsurface is the result.
EXAMPLE
Prudhoe Bay's Eileen Hydrate Accumulation
[0147] As stated earlier, in the Prudhoe Bay Reservoir, Alaska, the
natural gas accumulation is beneath the hydrate zone known as the
Eileen Hydrate Accumulation. This natural gas accumulation is
called the Prudhoe Bay Unit (PBU) gas cap. The hydrate accumulation
that overlies the PBU gas cap could be developed from (1) the
carbon dioxide that exists in the PBU gas cap or (2) methane in the
PBU gas cap could be utilized for power generation and the effluent
carbon dioxide captured and employed to produce the hydrates.
[0148] The composition of the hydrate in the Eileen accumulation is
nearly 100% methane. As shown above, the PBU gas cap contains about
13 mole % carbon dioxide. Separation of this carbon dioxide is
needed before pipeline shipping of the methane. This captured
carbon dioxide could be used to produce the hydrates located above
the PBU gas cap.
[0149] FIG. 5A shows the phase relationships that exist for an
injectant (containing only about 13 mole % carbon dioxide) formed
directly from the PBU gas cap. Thus, FIG. 5A is a phase diagram
where the composition of the injectant is 75.02 mole % methane,
7.95 mole % ethane, 3.99 mole % propane, and 13.04 mole % carbon
dioxide. This is the natural composition of the gas cap that exists
in the PBU.
[0150] FIG. 5B is a phase diagram where the composition of the
injectant is 43.13 mole % methane, 4.57 mole % ethane, 2.29 mole %
propane, and 50.00 mole % carbon dioxide. This is the Prudhoe Bay
gas cap composition with sufficient added carbon dioxide to
increase the carbon dioxide content to 50.00 mole %. At this
mixture of gas cap gas and carbon dioxide, the injectant forms a
liquid that is below fracture gradient. Although testing of whether
the fractures formed above fracture gradient are vertical or
horizontal is needed to determine if fractures would breach the
subsurface containment. Field tests are needed to verify the
fracture gradient.
[0151] FIGS. 5A and B are pressure and temperature diagrams that
show:
[0152] 1. The phase diagram and envelope (lines 560 and 612) of an
injectant where the injectant is of the specified composition, the
phases of the injectant that have a liquid phase (or critical
phase) and are shaded for three conditions where methane vapor
exists:
[0153] (a) The liquid and vapor phase of the injectant co-exist and
the injectant has a density greater than the vapor released upon
dissociation of the hydrate (areas 550 and 600);
[0154] (b) The liquid phase of the injectant exists (that is, there
is no vapor phase of the injectant) or the critical phase of the
injectant exists and the injectant has a density greater than the
vapor released upon dissociation of the hydrate and the pressure is
below the fracture pressure gradient (area 602); and
[0155] (c) The pressure is above the fracture pressure gradient
(areas 552 and 604).
[0156] 2. The phase envelope (lines 558 and 610) for 100% methane.
For this phase envelope, the hydrate phase is in the higher
pressure and lower temperature region and the vapor phase is in
either the lower pressure or higher temperature regions. The
typical composition of an in-place hydrate is near 100%
methane.
[0157] 3. The specific temperature and pressure profile of a well
(lines 556 and 608) within the area of hydrate occurrence. This is
the temperature and pressure profile for each well. The
intersection of the well bore pressure and temperature gradient
(lines 556 and 608) with the methane phase envelope (lines 558 and
610) shows where the in-place hydrates are stable and can exist in
the subsurface.
[0158] 4. The fracture gradient for the well (lines 554 and 606) is
the injection pressure which, if exceeded, will fracture the
formation. The fracture pressure of a well, where hydrates are
stable, depends on the depth of the hydrates. The maximum fracture
pressure is based upon the maximum depth of the hydrate occurrence.
Fractures can breach the subsurface containment and cause pressure
leak off. Vertical fractures can leak off to low pressure zones.
Whether vertical fractures occur is dependent on local stress
conditions or perhaps other factors. Horizontal fractures may even
help the production process. The area shaded 552 and 604 can
contain non-liquid injectant.
[0159] For the pressure and temperature profiles for the
arctic-permafrost setting, a pressure gradient of 0.421 psi/ft and
a fracture gradient of 0.695 psi/ft were used. For the pressure
gradient for the marine-continental shelf setting, a pressure
gradient of 0.45 psi/ft and a fracture gradient of 0.695 psi/ft
were used. Temperature gradients were taken from T. S. Collett et
al., "Natural Gas Hydrates", SPE-AAPG Western Region Meeting, May
23, 2002, Anchorage, Ak. Fracture gradients, well bore pressures,
and temperature gradients are dependent on the conditions specific
to the location of the well.
[0160] It should be noted that if the injectant is above the
critical point of the injectant, the injectant is a single phase.
For pure carbon dioxide, a temperature 87.87.degree. F., a pressure
of 1071 psia and a volume 0.0342 cu ft/lbm. constitute the critical
point (see Robert S. Metcalf, Petroleum Engineers Handbook, Table
20.2 Some Physical Constants of Hydrocarbons). At conditions such
as these, the injectant has the characteristics of a single phase.
This critical phase can be used as a liquid injectant if the
density is greater than the vapor released from the hydrate at
subsurface conditions. Phase and density data specific to the
injectant and to the in-place hydrate composition where this
invention is to be used should be obtained from laboratory analyses
to ensure that the appropriate relationships between pressure,
temperature, and density for the injectant are used in the
inventive system.
The Gas Cap in the Prudhoe Bay Unit (PBU)
[0161] The gas cap in the PBU contains 23 TCF (trillion cubic feet)
of gas containing 13 mole % CO.sub.2. Separating this carbon
dioxide, then injecting the carbon dioxide into the Eileen hydrate
to produce methane, and sequestering the carbon dioxide there would
significantly reduce the amount of greenhouse gases being released
into the atmosphere and at the same time would produce large
amounts of methane. There exists over 400 TCF of hydrates located
under the North Slope of Alaska.
[0162] The current proposal to exploit the gas cap in the PBU is to
construct a gas pipeline connecting the North Slope to the lower 48
states' gas pipeline grid. The lower 48 states' gas pipeline grid
would then supply the methane to electric power plants in the lower
48 states where the carbon dioxide (created by burning the methane
in the electric power plants) could not or would not be sequestered
(i.e., the carbon dioxide would be released into the atmosphere).
In this plan, the methane from hydrate production can be used to
offset costs associated with the gas removal of CO.sub.2 of the PBU
gas and provide natural gas with less requirements for carbon
dioxide removal. The clean up of the gas is expected to range from
$1.5-2.0 Billion.
[0163] My better plan is to exploit the gas cap in the PBU by using
the gas to generate electric power at the North Slope of Alaska and
to construct electric power lines (such as high voltage direct
current (HVDC) lines) connecting to the lower 48 states' power
grid. My plan would be implemented instead of constructing the
proposed gas pipeline connecting the North Slope to the lower 48
states' gas pipeline grid. Under my plan, the carbon dioxide
produced by burning the methane in the electric power plants would
be captured and then injected into the Eileen hydrate to produce
methane. The carbon dioxide would be sequestered there,
significantly reducing the amount of greenhouse gases being
released into the atmosphere and at the same time producing large
amounts of methane.
[0164] Many of the lower 48 states' power plants are older and
release significant amounts of carbon dioxide into the atmosphere.
A large number of new electric power plants are envisioned to use
this gas from the proposed North Slope pipeline. The U.S.
Department of Energy's Solid State Energy Conversion Alliance
(SECA) suggests that new electric power generation technologies
will result in a considerable reduction in the cost of electric
power generation and that these new technologies will be available
in the near term (within five years).
[0165] Thus, instead of building the proposed new gas pipeline and
a large number of new electric power plants in the lower 48 states,
my better plan is to build the new electric power plants in Alaska
on the North Slope in order to utilize the North Slope gas. At the
same time, my plan would sequester the carbon dioxide produced by
the power plants while producing more methane from the in-place
hydrates.
[0166] Some of the new electric power generation technologies, such
as fuel cells, not only produce less carbon dioxide and NO.sub.x
but also can run on fuels containing carbon dioxide and the
products are electricity, heat, and carbon dioxide. Instead of
expanding the U.S. contribution of carbon dioxide to the
atmosphere, my plan would capture the carbon dioxide and use it to
produce methane from the hydrate deposits that were not previously
economical to exploit. The net result of my plan is to provide
electric power at a lower cost.
[0167] By locating the power plants where hydrates exist, the
carbon dioxide produced from power production could be injected
into the hydrate zones. If it is assumed that 2.5-6.5 BCF (billion
cubic feet) of natural gas per day would be sent through the
proposed pipeline, then a significant percentage (preliminary
estimates of 30-100%) of the carbon dioxide that the U.S. produces
in excess of the baseline for the Kyoto accord could be injected
and sequestered from the atmosphere and used to produce some of 400
TCF of methane gas that exists in hydrates under the North Slope of
Alaska. Currently methane production in the US has stabilized from
prior declines because of coal bed methane and deep gas sources but
no net production increase exists; the question of whether new
resources can be developed to account for the production decline
from natural gas reservoirs within the US is critical to US energy
policy.
[0168] While the preferred embodiments of the invention have been
illustrated and described, it will be appreciated that various
changes can be made therein without departing from the spirit and
scope of the invention. While the preferred embodiment of the
invention has been illustrated and described, as noted above, many
changes can be made without departing from the spirit and scope of
the invention. Accordingly, the scope of the invention is not
limited by the disclosure of the preferred embodiment. Instead, the
invention should be determined entirely by reference to the claims
that follow.
* * * * *