U.S. patent application number 09/954548 was filed with the patent office on 2003-03-20 for use of underground reservoirs for re-gassification of lng, storage of resulting gas and / or delivery to conventional gas distribution systems.
Invention is credited to Wilson, Scott James.
Application Number | 20030051875 09/954548 |
Document ID | / |
Family ID | 25495588 |
Filed Date | 2003-03-20 |
United States Patent
Application |
20030051875 |
Kind Code |
A1 |
Wilson, Scott James |
March 20, 2003 |
Use of underground reservoirs for re-gassification of LNG, storage
of resulting gas and / or delivery to conventional gas distribution
systems
Abstract
The present invention is a method for re-gassifying Liquefied
Natural Gas (LNG) in a subterranean formation/cavity, storing the
resulting gaseous hydrocarbon in the same or connected strata, then
subsequent conventional production and delivery of the gas to end
users. LNG is injected into a permeable subterranean reservoir
through surface and wellbore equipment suitable for operations at
cryogenic temperatures. The liquid hydrocarbon vaporizes in the
permeable rock/cavity near the injection wellbore as it gains
thermal energy from the surrounding strata. The resulting gas is
held within the reservoir for subsequent production and/or
immediately produced by producing wells in the same or contiguous
formations. The invention eliminates the need for onshore LNG
receiving/storage terminals.
Inventors: |
Wilson, Scott James;
(Littleton, CO) |
Correspondence
Address: |
Scott James Wilson
7247 South Sundown Circle
Littleton
CO
80120
US
|
Family ID: |
25495588 |
Appl. No.: |
09/954548 |
Filed: |
September 17, 2001 |
Current U.S.
Class: |
166/268 ;
166/272.1 |
Current CPC
Class: |
B65G 5/005 20130101 |
Class at
Publication: |
166/268 ;
166/272.1 |
International
Class: |
E21B 043/16 |
Claims
I claim:
1. A method of storing natural gas comprising liquefying natural
gas to obtain liquefied natural gas ("LNG"), transporting the LNG
to a location near a subterranean reservoir within a formation, off
loading the LNG into the reservoir, and permitting the ambient heat
of the formation to vaporize the LNG into the natural gas.
2. The method of claim 1 wherein the LNG is offloaded into the
reservoir through at least one injection well in fluid
communication with the reservoir.
3. The method of claim 1 wherein the gas is withdrawn from the
reservoir through at least one production well in fluid
communication with the reservoir.
4. The method of claim 1 wherein the gas reservoir has a flow
capacity, with respect to gas, of at least about 1000 md-ft.
5. The method of claim 1 wherein the reservoir has a flow capacity,
with respect to gas, of at least about 10,000 md-ft.
6. The method of claim 1 wherein the reservoir has a flow capacity,
with respect to gas, of at least about 100,000 md-ft.
7. The method of claim 2 wherein the injection well is capable of
receiving cryogenic fluids.
8. The method of claim 2 wherein the injection well is capable of
injection rates of the LNG in the range of about 1,000 to about
100,000 barrels per day.
9. A method of storing natural gas comprising liquefying the
natural gas to obtain liquefied natural gas, ("LNG"), transporting
the LNG to a location near a subterranean gas reservoir wherein the
reservoir has a flow capacity of at least about 10,000 md-ft,
offloading the LNG into the reservoir through at least one
injection well capable of receiving cryogenic fluids and which is
in fluid communication with the reservoir, permitting the ambient
heat of the formation to vaporize the LNG back into the natural
gas, and withdrawing the natural gas through at least production
well in fluid communication with the reservoir.
10. The method of claim 9 wherein the reservoir has a flow
capacity, with respect to gas, of at least about 100,000 md-ft.
11. The method of claim 9 wherein the injection well is capable of
injection rates of at least about 10,000 to about 50,000 barrels of
LNG per day.
Description
TECHNICAL FIELD
[0001] This invention relates to a method of storing liquefied
natural gas ("LNG") in a subterranean reservoir. The LNG is
injected into an injection well in fluid communication with the
subterranean reservoir, and the ambient heat of the reservoir and
the surrounding formations vaporizes the LNG. The resulting natural
gas is delivered to a point of end use via conventional gas
transmission means.
BACKGROUND OF THE INVENTION
[0002] LNG is defined by the Gas Processors Suppliers Association
("GPSA") as a liquefied gas consisting of hydrocarbon components
typically including methane, ethane, propane, and normal and
iso-pentane as well as some trace impurities (FIG. 1.1, GPSA
Engineering Data Book, Gas Processors Suppliers Association, 2000,
Gas Processors Suppliers Association, 6526 E. 60th St., Tulsa,
Okla. 74145). At atmospheric pressure, methane, which is the main
component of LNG and generally present in concentrations of about
80-100% by volume, is a liquid at temperatures between its normal
boiling point of about -259.degree. F., and above its freezing
point at about -296.degree. F. Within these temperature ranges,
methane predominant LNG has a density of about 0.5 gm/cc and a
viscosity of about 0.12 centipoise (Friend, D., Ely, J., Ingham,
H.; Tables for the Thermophysical Properties of Methane, April,
1989, National Institute of Standards and Technology, Boulder,
Colo., 80303-3328).
[0003] In the operation of LNG transportation, storage, and gas
delivery, it is customary to deliver LNG to on-shore receiving
facilities by ocean-going tankers carrying LNG chilled to
-270.degree. F. The receiving facilities store the LNG in liquid
form once it is off loaded from the tankers. When sufficient end
user demand occurs, the LNG is converted back to gaseous form
immediately prior to its delivery to transmission lines. From the
transmission pipelines, it is moved to end users in gaseous form.
This process typically starts by offloading LNG tankers into
onshore LNG storage vessels using pumps and piping capable of
transferring cryogenic liquids. LNG is re-gassified by adding heat
and the resulting gas is piped through metering facilities into
natural gas transmission lines for ultimate delivery to
markets.
[0004] The equipment required at the receiving terminal includes
docks capable of berthing an LNG tanker, cryogenic pumps and piping
capable of transferring LNG from the tankers to the storage tanks,
cryogenic storage tanks, re-gassification equipment, a source of
heat capable of introducing sufficient heat to vaporize the LNG,
piping connections and measurement facilities for metering and
delivering the gas into a natural gas distribution system.
[0005] Problems associated with these receiving facilities include
the high cost and risk of berthing ships along coastlines at
specialized docks capable of receiving LNG tankers, the high cost
of cryogenic storage facilities, the cost and energy required to
convert the LNG back to gaseous form, and the need to install new
pipelines and metering systems required to deliver gas to a
transmission line or gas distribution system.
[0006] Also, the safety precautions required to berth and unload
ocean-going LNG tankers creates complexities since onshore
facilities near population centers are discouraged due to a real or
perceived probability of industrial accidents. The very large
initial capital investment, significant recurring operating costs,
and environmental and community related drawbacks have discouraged
construction of onshore receiving facilities (U.S. Pat. No.
4,365,576).
[0007] Prior art solutions attempting to eliminate onshore LNG
receiving facilities include U.S. Pat. No. 5,511,095 which
describes direct injection of LNG into subterranean man-made
cavities capable of receiving and storing the LNG in a dense phase.
U.S. Pat. No. 5,511,095 relies on storing the LNG at prescribed
pressures and temperatures in the subsurface so that LNG does not
return to gas phase. While pressure can be controlled in subsurface
cavities by a variety of means, the temperature of the cavity will
continuously attempt to return to the ambient temperature of the
subsurface.
[0008] Except in the Polar Regions, ambient subsurface temperatures
rarely fall below 50.degree. F., so maintaining subsurface
temperatures low enough to keep LNG from flashing back to gaseous
phase is impossible without an active cooling mechanism: e.g.,
refrigeration or introduction of cold fluids. To store the LNG as
any phase but gas, the temperature of the cavity must remain below
about -116.degree. F., which is the critical temperature of
methane. Critical temperature is defined as the maximum temperature
at which a pure component can exist as a liquid.
[0009] U.S. Pat. No. 5,511,095 relies on displacing the "dense
phase" LNG with saline water or brine. Brine freezes at
temperatures significantly higher than about -116.degree. F. where
methane-based LNG will become gaseous. Displacement with brine at
these temperatures will create significant problems in the cavity
and wellbores connecting the cavity to the surface: e.g., the
interface in the reservoir at the boundary between the LNG and the
displacing fluid will freeze and no longer move with the differing
fluid levels, while any brine in a wellbore at these temperatures
will freeze.
[0010] Academic work designed to evaluate the permeability
reduction caused by injecting natural gas at cold temperatures into
subterranean formations found that permeability decreased
significantly, but, in no case was a total loss of injection
experienced. The current art of injecting cold fluids in water
saturated porous media is characterized by significant permeability
reduction and difficult injection due to ice and hydrate formation
and other deleterious effects (Sturgeon-Berg, R., Permeability
reduction effects due to methane and natural gas flow through wet
porous media, Master of Science Thesis, Chemical and Petroleum
Refining Engineering Department, Colorado School of Mines, Golden,
Colo., U.S.A. 1996.).
[0011] The current state of the art in ocean bound LNG delivery is
characterized by continued use of onshore cryogenic LNG storage and
re-gassification facilities. U.S. Pat. No. like 4,365,576 describe
a means of storing cryogenic liquids in man-made offshore storage
vessels but these have not gained widespread use. The current
system is costly and is projected to "eventually manifest itself as
a choke point in the U.S. system." (Economides, M., Oligney, R.,
and Demarchos, A., "Natural Gas: The Revolution Is Coming," Journal
of Petroleum Technology, Society of Petroleum Engineers. May,
2001(p66), Dallas Tex., U.S.A.).
[0012] It is an object of the invention to use the ambient
temperature and warming capacity of subsurface formations to
gassify the LNG injected into the subsurface reservoir.
[0013] Another object of the invention is to use existing porous
reservoirs to store LNG in gaseous form.
[0014] It is an object of this invention to obtain a more
economical and efficient method of delivering LNG to the
market.
[0015] A further object of the invention is to use existing
transmission systems in fluid communication with the reservoir to
deliver natural gas to the market.
SUMMARY OF THE INVENTION
[0016] To achieve the foregoing and other objects, and in
accordance with the purposes of the present invention, as embodied
and broadly described herein, conventional subterraneous porous
fluid reservoirs are used to receive and store LNG. The LNG is
injected into an injection well capable of withstanding cold
temperatures: e.g., down to about -296.degree. F., and in fluid
communication with the reservoir. As the LNG begins moving down the
wellbore and into portions of the reservoir away from the injection
well, the LNG absorbs heat from the surrounding formations until it
eventually reaches the ambient temperature of the formation, which
is approximately 1.5.degree. F. higher than surface temperature for
each 100 ft. of depth below the surface. The resulting gas will
come to temperature equilibrium with the surrounding formation over
a period of a few hours and at most a few days. Once the LNG is in
the subsurface, the tendency of the subterranean formation to warm
the LNG to ambient temperature is continuous and for all intents
and purposes, infinite. The resulting gas is stored in the
reservoir until it is produced through one or several production
wells in fluid communication with the reservoir and the gas is
withdrawn for delivery to the market.
BRIEF DESCRIPTION OF THE DRAWINGS
[0017] The accompanying drawings, which are incorporated in and
form a part of the specification, illustrate the embodiments of the
present invention and, together with the description, serve to
explain the principles of the invention.
[0018] In the drawings:
[0019] FIG. 1 is an elevational view of an LNG tanker off-loading
LNG into an injection well in fluid communication with a reservoir
that is in fluid communication with two production wells.
[0020] FIG. 2 is an elevational view of an injection well capable
of receiving cryogenic fluids in fluid communication with a gas
reservoir that is also in fluid communication with a production
well.
DESCRIPTION OF THE PREFERRED EMBODIMENTS
[0021] This invention relates to improvements in the method of
delivering LNG to conventional gas users by eliminating onshore
surface receiving cryogenic storage facilities. The initial capital
cost, the ongoing operations expense, the onshore land acreage,
operations manpower, and shoreline community hazards, and exposures
to risk are reduced by this invention.
[0022] These benefits are accomplished by offloading LNG from
tankers directly into conventional subterranean reservoirs through
traditional injection wells fitted with wellbore equipment capable
of operations at cryogenic temperatures. The LNG tanker can be
berthed at offshore unloading facilities in close proximity to the
injection wellheads. The wellheads can be located on a multi-well
platform, on single well structures, on the sea-bottom with a
surface tie-in injection lines, on near shore injection wells and
on other facilities tied into a cryogenic transport line from the
tanker to the injection well. The LNG is stored in gaseous form in
subterranean reservoirs at ambient conditions. The invention
eliminates re-gassification facilities since the LNG is vaporized
after it reaches the subterranean reservoir by utilizing heat from
the surrounding strata to gassify the LNG. The present invention
takes advantage of the ambient temperatures of the subterranean
reservoir to impart heat to the injected fluid, and the injected
fluid's ability to displace and remove liquid water in near
wellbore areas that would normally decrease injectivity of the
injection well.
[0023] The invention reduces the need for gas gathering, metering,
and transmission line tie-ins if a reservoir is used that was
previously or currently used for traditional gas production. If a
recently decommissioned gas production field is used or one still
on production, gas gathering and/or transmission line tie-ins can
be used. Gas can be produced from production wells concurrently
with LNG injection or as demand requires. This invention simplifies
offshore handling if a suitable reservoir that is in fluid
communication between the offshore and onshore surface locations is
used, since LNG can be injected offshore and natural gas produced
at the onshore location.
[0024] The present invention differs from the prior art in that it
uses underground reservoirs with sufficiently high native
permeability and infectivity that injection of the LNG can be
initiated. In addition, wellbore conditioning is carried out and
maintained in injection wells to ensure adequate infectivity.
Conditioning includes minimizing water saturation by repeated
injection of dry gas, thus decreasing water saturation by
evaporating, vaporizing, subliming, and absorbing water in which
the LNG comes in contact. The effect of the reduction in water
saturation in the flow paths followed by the LNG will be to
maintain permeability with respect to the injected LNG.
[0025] Gas resulting from re-gassification of LNG is dry: i.e.,
contains no measurable water in liquid or vapor form, and will come
to thermodynamic equilibrium with the water in the reservoir until
the gas becomes water saturated. This gas is produced to the
surface and any undesirable water is removed before being sent to
the gas purchaser, resulting in a net decrease in the water within
the reservoir. Although the total amount of water in the reservoir
cannot be affected significantly, the area around the injection
wellbores can, since the near-wellbore area will be flushed
extensively with water-free gas/LNG. Since no additional water is
introduced into the reservoir near the injection well, the flow
paths taken by the LNG/gas will eventually become water-free. For
example, one million cubic feet of a typical water free natural gas
at 150.degree. F. and 1000 psia can absorb 220 pounds of liquid
water while coming to equilibrium with a liquid water saturation
(see GPSA page 20-2,GPSA Engineering Data Book, Gas Processors
Suppliers Association, 2000, Gas Processors Suppliers Association,
6526 E. 60th St., Tulsa, Okla. 7414500). Therefore, a single tanker
load of 3 bcf (billion cubic feet) of LNG could remove 660,000
pounds or 1900 bbls of water from the flow paths of the LNG/gas.
The resulting water-free flow paths will provide excellent conduits
for future injection of LNG. Injectivity should continue to improve
until it approaches a highly favorable single-phase liquid relative
permeability.
[0026] Injection of LNG continues until offloading of the tanker is
complete. The gas reservoirs best suited are those that have flow
capacities above about 1000 md-ft and preferably above about 10,000
md-ft, and most preferably above 100,000 md-ft. The permeabilities
and injection rate of the injection well should permit offloading
of the LNG at rates of about 1000 bbl/day to about 50,000 bbl/day
and preferably about 10,000 bbl/day to about 50,000 bbls of
LNG/day. The reservoir should also have gas "storage" volume
sufficient to accept a full load of LNG without overpressuring the
reservoir. In addition, the reservoir should not have a water
influx greater than about 1000 bbl/day to about 10,000 bbl/day and
preferably about 0 bbl/day to about 1000 bbl/day: this will help
the reservoir to maintain containment-like behavior and reduce the
introduction of new water to injection wellbores that have been
de-watered and/or conditioned to reduce water saturation. Heat flux
into the reservoir from surrounding strata will bring the gas to
ambient temperature in a matter of days. It is preferred that the
reservoir not be significantly affected by an aquifer that would
re-introduce substantial quantities of water into the
reservoir.
[0027] If LNG injection does not sufficiently decrease water
saturation, other methods of decreasing water saturation near the
wellbore can be used to pre-condition injection wells for LNG
injection. These other methods include the use of fireflood
techniques to vaporize and displace water around the injection
wellbore, injection of surfactants to allow increased gravity
related water drainage, injection of chemicals to absorb and/or
adsorb water off of the reservoir rock, or other dehydration
methods used in the current art.
[0028] By reducing or eliminating water saturation in the injection
well, injection of LNG should follow the same pressure--flow rate
relationships commonly used in the current art of petroleum
reservoir engineering as defined by Darcy's law. Darcy's law states
that the flow-rate through porous media is proportional to the
cross sectional area, the permeability, and the pressure
differential, while flow-rate is inversely proportional to the
viscosity of the flowing fluid and the length of flow path. Wells
capable of injecting a 0.12 centipoise liquid at the required flow
are common in the prolific sands of the U.S. gulf coast and other
coastal offshore subterranean reservoirs throughout the world.
[0029] Injection rates in injection wells sufficient for efficient
offloading of large LNG tankers (135,000 m.sup.3) are generally
within the range of about 20,000 bbl/day/well to about 50,000
bbl/day/well and preferably about 50,000 bbl/day/well to about
100,000 bbl/day/well and most preferably above 100,000 bbl
LNG/day/well. To accomplish a one-day offloading turnaround,
approximately 10 injection wells are required. Horizontal and
fractured wells can be used to provide higher injectivity if
necessary. In the Gulf of Mexico, wells capable of injection at
these rates are currently producing gas into well-established gas
gathering systems.
[0030] As the pressures in existing, state of the art reservoirs
are depleted, the producing zones may be abandoned and the wells
plugged. A few of these same wells could be "unplugged" and used
for LNG injection, the low pressure reservoirs used for storage,
and the multitude of current platform, gathering systems, and
producing wells used for production as-is; thus, this invention
could avoid the great expense presently incurred in the current art
in abandoning these platforms and wells.
[0031] Gas reservoirs suitable for this invention can be described
as high permeability, competent porous formations with low pressure
due to depletion, but high fracture gradients so that the formation
can be repressured completely if desired. The size of the reservoir
should be large enough to meet the needs of the LNG delivery
schedule in conjunction with the gas offtake schedule. A preferred
embodiment has existing gas production wells and gathering,
metering and trunk line connections so that delivery to the gas
distribution network is simple.
[0032] Injection wells suitable for this invention can be described
as fitted with cryogenic capable injection lines, wellheads, and
tubulars and preferably wellbore equipment and casing strings.
Large tubular strings of at least 31/2" outer diameter and
preferably larger will enable larger injection rates. Tubular
strings preferably should be fitted with multiple
expansion/contraction joints or other means to allow anticipated
movement due to temperature fluctuations. Tubing strings should
also be fitted with sufficient pressure relief systems to
accommodate a blockage and resulting reverse flow after the
wellbore fluids re-gassify.
[0033] The present invention greatly simplifies the process of
receiving and storing LNG in locations where conventional offshore
oil and gas fields exist. Since these fields generally deliver gas
into the gas transmission system, the ability to move ocean-borne
LNG to end-users is more efficient and economical than conceived in
the prior art. In its simplicity and efficiency, the present
invention not only eliminates the cost and hardship incurred in
building new facilities, but also extends the productive lives of
offshore gas production assets considered uneconomic and soon to be
permanently abandoned.
DESCRIPTION OF THE DRAWINGS
[0034] The actual operation and apparent advantages of the present
invention will be better understood by referring to the drawings
which are not necessarily to scale and in which like numerals
identify like parts and in which:
[0035] FIG. 1 illustrates the preferred method for carrying out the
injection, regassification, storage, and ultimate delivery of
hydrocarbon gas previously existing in the liquefied form. LNG
tanker 2 delivers a load of LNG to offshore injection well 4.
Docking facilities 6 similar to those used in Floating Production
and Storage Operations (FPSO) vessels can be used to tether and
maintain position of the LNG Tanker near the injection well
location. Transfer pumps 8 capable of handling cryogenic fluids
housed either on the tanker itself, on the wellhead platform 18, or
on a service vessel are used to transfer LNG from the tanker to the
injection well. After the lower section 10 of injection well 4 is
sufficiently cooled, the LNG (some of the LNG may be converted to
gas due to heat being absorbed by the LNG) begins dispersing out
through perforations 12 into the subterranean gas reservoir 14.
[0036] While liquefied gas contacts the underground formations, it
is heated by the ambient heat present in subterranean formations 26
and in the reservoir itself 14. LNG continuously vaporizes and
moves toward lower pressures that exist in other parts of the
reservoir near producing wells 20 and 22. Given sufficiently high
injection rates, vaporization may not occur until the LNG has
flowed away from the injection well 10. However, the capacity of
the formation to warm the LNG to ambient conditions is essentially
infinite, so the LNG will eventually return to a gas phase and
approach ambient temperature. The resulting increase in pressure as
the LNG returns to the gas phase will force flow toward lower
pressure production wells and areas of the reservoir farther away
from injection sources.
[0037] High permeability, low-pressure reservoirs of moderate size
(10-15 bcf) provide the best reservoirs for application of this
invention since such reservoirs require low injection pressure to
introduce LNG into the formation, move gaseous hydrocarbon quickly
to producing wells, and provide high deliverability at the
producing wells. There is no requirement for a specific size.
However, a reservoir size of less than a tanker load (approximately
3 bcf) could be used as a regassification means and alternate
docking method to conventional LNG facilities. Larger reservoirs
could be charged continuously or seasonally for long-term gas
storage and/or peak production needs. Even those reservoirs that
have previously been abandoned may be candidates since their
production characteristics are well known, thus reducing the risk
associated with unpredictable reservoir performance.
[0038] The benefits of injecting gas in liquefied form are many. No
regassification equipment is required. Injection is accomplished
with pumps 8, which are simpler and less expensive than the
compressors that would be required for the same mass injection
rates of gaseous hydrocarbons. The hydrostatic head of the
injection liquid provides additional pressure energy for injection
since the accumulated mass of the LNG in the wellbore serves to
push LNG into the reservoir 14. Conversely, producing wells can be
located offshore 20 or onshore 22 if the subject reservoir extends
onshore. In general, using the LNG injection wells for subsequent
production is not advised, since this could re-saturate the
near-wellbore region of the injection well with water produced
along with the gas. Once delivery of the gas is needed, gas is
produced from production wells into a gathering system or gas
transmission system 24.
[0039] FIG. 2 illustrates the present method for delivering LNG to
the underground gas reservoir 14. LNG is injected from a surface
location into a cryogenic tubing string 32. LNG moves down the
wellbore at velocities exceeding the bubble rise velocity of
natural gas which is approximately 7 feet/second. LNG exits the
wellbore 34 in gas and/or liquid form into the open casing 36 that
is adjacent to the reservoir. Technology developed for the
steamflood and LNG handling industries can be used in constructing
competent wellbores for purposes of injection. The current art in
these industries includes ductile metallurgies at cryogenic
temperatures, expansion/contraction fittings and seals, and
insulated casings and cements 38. Low heat-flux annular fluids like
gelled diesel can be used to isolate upper sections of the wellbore
from extreme temperature variations 40 and maintain LNG in liquid
form if it is deemed advantageous. The present invention
incorporates injection into the formation in either gas, liquid or
mixed phase; during the offloading of a tanker all three phases may
exist at times.
[0040] After the LNG enters the casing 36, it is forced into
conventional perforations 42. After traveling the length of the
perforations, it flows into the outer reaches of the reservoir 14.
The area of the reservoir near the injection wellbore 44 will have
an extremely low water saturation after the LNG and dry gas has
been injected for a sufficient time to remove the liquid water in
the pore spaces. For the maximum injection rate, LNG will move as a
liquid away from the wellbore toward lower pressures.
[0041] As the formation warms the LNG, the LNG begins to vaporize
46 and moves away from the LNG saturated areas of the formation
toward production well 50. After the ambient temperature of the
formation heats the LNG to gassify it, the gas moves within the gas
reservoir 14 according to pressure gradients induced by production
and injection wells. Gas can remain in the reservoir until seasonal
or cyclic demand requires production of the gas through production
well 50 or can be produced concurrently with injection.
[0042] While the foregoing preferred embodiments of the invention
have been described and shown, it is understood that the
alternatives and modifications, such as those suggested and others,
may be made thereto and fall within the scope of the invention.
* * * * *