Note: Descriptions are shown in the official language in which they were submitted.
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T 8563 II
RECOVERING HYDROCARBONS
This invention relates to an improved method and apparatus for
recovering hydrocarbons from a hydrocarbon-containing subterranean
formation.
USA patent specifications No. 4 640 352 and No. 4 886 118 and
"Under Ground Shale Oil Pyrolysis According to the Ljunstroem
Method", Chief Engineer Goesta Salomonsson, IVA, vol. 24 (1953),
No. 3, pp 118-123 disclose conductive heating of subterranean
formations that contain hydrocarbons to recover hydrocarbons
therefrom. Conductive heating is particularly applicable to low
permeability formations such as diatomites, porcelanite, coal, oil
shales and other source rocks. Formations of low permeability are
not amenable to hydrocarbon recovery methods that require injection
of fluids into the formation such as steam, carbon dioxide, or fire
flooding because flooding materials tend to penetrate formations
having low permeability preferentially through fractures, The
injected fluids bypass most of the formation hydrocarbons. In
contrast, conductive heating does not require fluid transport into
the formation. Formation hydrocarbons are therefore not bypassed as
in a flooding and in-situ combustion process. When the temperature
of a formation is increased by conductive heating, vertical
temperature profiles will tend to be relatively uniform because
formations generally have relatively uniforra thermal conductivities
and specific heats. Production of hydrocarbons in a thermal
conduction process is by pressure drive, vaporization and thermal
expansion of hydrocarbons and water trapped within the pores of the
formation rock. Hydrocarbons migrate through small fractures
created by the expansion and vaporization of the hydrocarbons and
water.
USA patent specification No. 4 640 352 discloses 600 °C to
900 °C as a preferred temperature range for heat injection for the
thermal conduction process. Electrical resistance is disclosed as a
C~1~~~~~~~>
_ 2 _
preferred heat source for the thermal conduction process. The
process described in the Salomonsson article uses electrical
resistance heat injectors and a heat injection rate of about
790 W/m (Watts per meter). This rate of heat input would result in
an injection temperature within the temperature range of about
600 °C to 900 °C.
This heat conduction process has been known for a relatively
long time, yet can not be performed economically. Commercial
applications are not economical mainly due to the long time period
required to produce hydrocarbons with a reasonable number of wells.
A sufficient amount of capital can not be justified by
hydrocarbon production that will not be realized for such a long
time period.
The high cost of electrical energy is also an impediment to
commercial projects using these prior art methods. Conversion of
hydrocarbons to electrical energy is typically accomplished at only
about 35 percent efficiency and requires a considerable capital
investment. Directly burning hydrocarbons considerably lowers
energy costs.
Gas fired heaters which are intended to be useful for
injection of heat into subterranean formations are disclosed in USA
patent specification No. 2 902 270 and Swedish patent specification
No. 123 137. These burners utilize flames to combust fuel gas. The
existence of flames results in hot spots within the burner and in
the formation surrounding the burner. A flame typically provides a
1650 °C radiant heat source. Materials of construction for the
burners withstand the temperatures of these hot spots. The heaters
are therefore more expensive than a comparable heater without
flames. The heater of Swedish patent No. 123 137 would appear to
result in flameless combustion such as the present invention if the
combustion air and the fuel gas were heated to a temperature above
the autoignition temperature of the mixture. But due to the shallow
depths of the heat injection wells disclosed in that patent, the
components do not appear to be heated sufficiently to result in
flameless combustion. At burner temperatures above about 900 °C
about 30 m of wellbora would be sufficient to preheat the
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combustion air and the fuel gas for flameless combustion. Further,
radiant heat transfer from the flames appears to be critical in
obtaining the temperature profile indicated in Figure 2 of the
Swedish patent because little heat would be transferred from the
wellbore to the formation above the portion of the borehole
containing flames. Due to the existence of flames, the service life
and the operating temperatures of these burners are limited.
Figure 2 of the Swedish patent shows a temperature profile
within the heat injector wellbore, but the nature of radiant heat
transfer would not result in a uniform temperature profile such as
this. The temperature of the casing would be significantly greater
at points close to the flames. The average temperature of the heat
injector would therefore realistically be considerably lower than
the metallurgical limits of the well materials.
USA patent specifications No, 3 113 623 and No. 3 181 613
disclose gas fired heat injection burners for heating subterranean
formations. These burners utilize porous materials to hold a flame
and thereby spreading the flame out over an extended length.
Radiant heat transfer from a flame to the casing is avoided by
providing the porous medium to hold the flame. But for combustion
to take place in the porous medium, the fuel gas and the combustion
air must be premixed. If the premixed fuel gas and combustion air
were at a temperature above the autoignition temperature of the
mixture, they would react upon being premixed instead of within the
porous medium. The formations utilized as examples of these
inventions are only up to 15 m thick and below only about 15 m of
overburden. The fuel gas and the combustion air are therefore
relatively cool when they reach the burner. The burner would not
function as it was intended if the formation being heated were
significantly thicker or buried under significantly more
overburden.
Natural gas fired well heaters that are useful for heating
formations to temperatures sufficient for ignition of in-situ fire
floods are disclosed in USA patent specifications No. 2 923 535,
No. 3 095 031, No. 3 880 235, No. 4 079 784, and No. 4 137 968.
~~~~~,f ~~~
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Provisions for the return of combustion gases to the surface
are not required for ignition of fire floods. The combustion gases
are intended to be injected into the formation. A long service life
is also not reduired due to the short time period during which the
burner is needed. The fuel gas and combustion air also remain
relatively cool as they go down a borehole toward the burner. These
burners are therefore not suitable for use as heat injectors, and
do not overcome the shortcomings of the prior art heat injector
burners.
It is therefore an object of the present invention to provide
a method to recover hydrocarbons from a hydrocarbon-containing
formation using a conductive heat transfer. It is another object to
provide such a process wherein more than about 75 percent of the
original hydrocarbons in place may be recovered. In a preferred
embodiment it is an object to provide such a process which is
capable of recovering hydrocarbon from a formation having a low
permeability such as oil shale or diatomite.
To this end the process of recovering hydrocarbons from a
hydrocarbon-containing subterranean formation having a low
permeability, according to present invention comprises the steps
of:
providing heat injection means extending essentially through
the hydrocarbon-containing subterranean formation, the heat
injection means effective to provide heat in at least one plane,
the plane being essentially perpendicular to the direction of the
minimum principal stress, and the heat injection means capable of
injecting heat at a temperature level of above about 900 °C;
providing at least one production well extending into the
hydrocarbon-containing subterranean formation;
injecting heat into the formation from the heat injection
means at a temperature level above about 900 °C thereby driving
hydrocarbons away from the heat injection means and toward the
production well; and
producing from the production well hydrocarbons that have been
driven away from the heat injection means.
The process of this invention utilizes a high temperature
front moving uniformly through the formation. The high temperature
front will vaporize connate water, water flood residual water and
hydrocarbons, creating what is essentially a steam drive using
in-situ generated steam. The steam drive is vertically uniform due
to the generation of the steam by the uniform high temperature
front. Recovery of original hydrocarbons in place is high as a
result of the absence of significant fingering such as that which
occurs in fluid injection processes. The high temperature of the
present injectors, along with the uniform temperature, permits
injection of heat at a rate which results in production of
hydrocarbons significantly faster than injection of heat at prior
art temperature levels.
In a preferred embodiment of the present invention, the
hydrocarbon-containing formation is a hydrocarbon-containing
diatomite formation. Diatomite formations include porcelanite type
formations such as the Monterey formation in California. Diatomite
formations have high porosity but low initial permeabilities. In
this preferred embodiment, foxmations are most preferably
hydraulically fractured from the production wells to minimize the
number of production wells required to drain the formation. In this
embodiment, the heat injection means are arranged between
production wells in rows that axe approximately perpendicular to
the direction of the minimum principle stress of the formation and
the formation is fractured from the production well. Production
proceeds as a line drive from the rows of heat injector wells to
the fractures of the production wells.
In the specification and in the claims the expression "low
permeability" is used to refer to a permeability which is lower
than 20 darcy.
The process of the present invention can also advantageously
be applied to formations having significant permeabilities. For
example, a thick deposit of tar sands may advantageously be
subjected to the process of the present invention. Formations such
as oil shale formations that have no initial permeability but tend
~~~~~a
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to develop permeability by fracturing and pyrolysis of solids upon
heating may also be subjected to the present process.
The invention also relates to an apparatus to recover
hydrocarbons from a hydrocarbon-containing subterranean formation
comprising:
a) a heat injection well extending from a surface wellhead to
within the subterranean formation;
b) a gas fired burner within the heat injection well capable of
heating the subterranean formation adjacent to the well to a
temperature greater than about 900 °C wherein combustion is
distributed over the length of the heat injection well within the
subterranean formation;
c) a means to provide a gas composition for combustion within the
gas fired burner that does not form carbon deposits when heated to
900 °C; and
d) a hydrocarbon production well.
The invention will now be described by way of example in more
detail with reference to the accompanying drawings, wherein
Figures 1 through 5 show burners suitable for use in the
present invention;
Figure 6 is a plot of calculated hydrocarbon recoveries as a
function of time for three different temperature levels of heat
injection from a hypothetical diatomite formation;
Figure 7 is a plot of the rate of heat injection to achieve
each of the temperature levels of Figure b;
Figure 8 is a plot of temperature profiles along a burner at
various temperatures; and
Figure 9 is a plan view of a preferred well pattern for the
practice of the present invention.
The heat injection means of the present invention may be any
means capable of operation continuously for extended time periods
at injection temperatures above about 900 °C and preferably above
about 1000 °C. Gas fuelled burners utilizing flameless combustion
are preferred. Gas, particularly methane, is a clean fuel. Use of a
clean fuel is essential for long term continuous operation.
a~a~~~~Ei~a
_ 7 _
Flameless combustion maximizes the temperature level at which
heat may be injected for any given materials of construction. Gas
is also an economical fuel, and inherently less expensive than
electricity.
Injectors utilizing fl.ameless combustion of fuel gas at
temperature levels of about 900 °C to about 1 100 °C may be
fabricated from high temperature alloys such as, for example,
INCONEL 617, INCOLOY SOOHT, INCOLOY 601, HASTELLOY 235, UDIMET 500
and INCOLOY DS. At higher temperatures ceramic materials are
preferred. Ceramic materials with acceptable strength at
temperatures of 900 'C to about 1400 °C are generally high alumina
content ceramics. Other ceramics that may be useful include chrome
oxide, zirconia, and magnesium oxide based ceramics. National
Refractories and Minerals, Inc., Livermore, California; A.P. Green
Industries, Inc., Mexico, Missouri; and Alcoa, Alcoa Center, Penn.,
provide such materials.
Generally, flameless combustion is accomplished by preheating
combustion air and fuel gas sufficiently that when the two streams
are combined the temperature of the mixture exceeds the auto
ignition temperature of the mixture, but to a temperature less than
that which would result in the oxidation upon mixing being limited
by the rate of mixing. Preheating of the streams to a temperature
between about 850 °C and about 1400 °C and then mixing the fuel
gas
into the combustion air in relatively small increments will result
in flameless combustion. The increments in which the fuel gas is
mixed with the combustion gas stream preferably result in about a
20 °C to 100 °C temperature rise in the combustion gas stream
due
to the combustion of the fuel.
Referring to Figure 1, a heat injection well and burner
capable of carrying out the present invention are shown. A
formation to be heated 1 is below an overburden 2. The heat
injection well is formed by a wellbore 3, which extends through the
overburden and to near the bottom of the formation to be heated. In
the embodiment shown in Figure 1, the wellbore is cased with a
casing 4. The lower portion of the wellbore may be cemented with a
_g_
cement 7, having characteristics suitable for withstanding elevated
temperatures arid transferring heat. A cement which is a good
thermal insulator $ is preferred for the upper portion of the
wellbore to prevent heat loss from the system. A combustion air
conduit 10 extends from the wellhead 11 to the lower portion of the
wellbore. A fuel gas conduit 12 also extends from the wellhead to
the bottom of the wellbore.
High temperature cements suitable for cementing casing and
conduits within the high temperature portions of the wellbore are
available. Examples are disclosed in USA patent specifications
No. 3 507 332 and No. 3 180 748. Alumina contents above about
50 percent by weight based on cements slurry solids are preferred.
Thermal conductivity of these cements can be increased by
including graphite in the cement slurry. Between about 10 and about
50 percent by weight of graphite will result in a significant
improvement in thermal conductivity. Cement slurries that contain
graphite are also of a significantly lower density than high
alumina slurries and generally are less expensive than high alumina
slurries. The lower density slurry enables conventional cementing
of wellbores whereas heavier slurries often required staged
cementing. Staged cementing requires considerable rig time.
Graphite containing cements are not particularly strong, and
are therefore not preferred when high strength is required. When a
substantial casing is utilized, high strength cement is not
required and high graphite cement is preferred.
Choice of a diameter of the casing 4 in the embodiment of
Figure 1 is a trade off between the expense of the casing, and the
rate at which heat may be transferred into the formation. The
casing, due to the metallurgy required, is generally the most
expensive component of the injection well. The heat that can be
transferred into the formation increases significantly with
increasing casing diameter. A casing of between about 10 and about
20 cm in internal diameter will typically provide an optimum
trade-off between initial cost and heat transfer. The casing 4
could optionally be provided with means to provide communication
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between the outside of the casing and the inside of the casing
after the well is brought up to operating temperatures. Such means
would relieve pressure from the outside of the casing. These
pressures are generated by formation gases that permeate the
cement. Relieving these pressures could permit the use of thinner
walled casings. Means to provide communication may be, for example,
partially milled portions which fail at operation temperatures and
pressures, or plugs of aluminitun or polymers that melt or burn at
service temperature and pressure. The plugs or milled portions
would serve to keep cement out of the casing while the casing is
being cemented into place.
The fuel gas conduit contains a plurality o~ orifices 13 (six
shown) along the length of the conduit within the formation to be
heated. The orifices provide communication between the fuel gas
conduit and the combustion air conduit. A plurality of orifices
provide for distribution of heat release within the formation to be
heated. The orifices can be sized to accomplish a nearly even
temperature distribution within the casing. A nearly even
temperature profile within the casing results in more uniform heat
distribution within the formation to be heated. A nearly uniform
heat distribution within the formation will result in more
efficient use of heat in a conductive heating hydrocarbon recovery
process. A more even temperature profile will also result in the
lower maximum temperatures for the same heat release. Because the
materials of construction of the burner and well system dictate the
maximum temperatures, even temperature profiles will increase the
heat release possible for the same materials of construction.
Alternatively, it may be advantageous to vary the temperature
profile within a wellbore to match operating limits which vary with
depth. For example, suspended alloy tubes could withstand greater
temperatures near the bottom due to the bottom portions supporting
less weight. Designing the burner to take advantage of varying
limitations may result in greater heat input into the formation and
therefore more rapid recovery of hydrocarbons.
~~~~i~~i~i
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The number of orifices is limited only by size of orifices
which are to be used. If more orifices are used, they must
generally be of a smaller size. Smaller orifices will plug more
easily than larger orifices. The number of orifices is a trade-off
between evenness of the temperature profile and the possibility of
plugging.
Alternatively, air could be staged into fuel gas by providing
orifices in the combustion air conduit instead of the fuel conduit.
Fuel gas and combustion air transported to bottom of the
wellbore combine and react within the wellbore volume surrounding
the conduits 14 forming combustion products. The combustion
products travel up the wellbore and out an exhaust nozzle 15 at the
wellhead. From the exhaust nozzle, the combustion products may be
routed to atmosphere through an exhaust stack (not shown).
Alternatively, the combustion gases may be treated to remove
pollutants. Energy recovery from the combustion products by an
expander turbine or heat exchanger may also be desirable.
As the combustion products rise in the wellbore above the
formation being heated, they exchange heat with the combustion air
and the fuel gas traveling down the flow conduits. This heat
exchange not only conserves energy, but permits the desirable
flameless combustion of the present invention. The fuel gas and the
combustion air are preheated as they travel down the respective
flow conduits sufficiently that the mixture of the two streams at
the ultimate mixing point is at a temperature above the
autoignition temperature of the mixture. Flameless combustion
results, avoiding a flame as a radiant heat source. Heat is
therefore transferred from the wellbore in an essentially uniform
fashion.
The preheating of the fuel gases to obtain flameless
combustion would result in significant generation of carbon within
the fuel gas conduit unless a carbon formation suppressant is
included in the fuel gas stream. Nozzles for infection of fuel gas
and oxidant are shown in Figure 1 as 16 and 17 respectively. The
carbon formation suppressant included in the fuel gas may be carbon
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dioxide, steam, hydrogen or mixtures thereof. Carbon dioxide and
steam are preferred due to the generally higher cost of hydrogen.
Carbon is formed from methane at elevated temperatures
according to the following reaction:
CH~E ----> C + 2H2
This reaction is a reversible reaction, and hydrogen functions
as carbon formation suppressant by the reverse reaction.
Carbon dioxide suppresses carbon formation by the following
reaction:
C02 + C ---~-> 2C0
Steam suppresses carbon formation by the following reactions:
H20 + C ----> CO + H2
2H20 + C ----> C02 + 2H2
The carbon dioxide and the carbon monoxide remain in
equilibrium at elevated temperatures according to the shift gas
reaction:
CO + H20 <----> C02 +H2
When the fuel gas is essentially methane, a molar ratio of
about 1:1 of steam to methane will be sufficient to suppress carbon
formation to temperatures of about 1371 °C and a molar ratio of
about 1.15:1 of carbon dioxide to methane is sufficient to suppress
carbon formation. The molar ratios of steam to methane is
preferably within the range of about 1:1 to about 2:1 when steam is
utilized as the carbon formation suppressant. The molar ratio of
carbon dioxide to methane is preferably within the range of about
1:1 to about 3:1 when carbon dioxide is utilized as the carbon
formation suppressant. The fuel gas preferably consists essentially
of methane due to methane being more thermally stable than other
light hydrocarbons. The carbon formation suppressant is
additionally beneficial because it lowers combustion rates and
reduces peak temperatures.
Referring now to Figure 2, an alternative apparatus capable of
carrying out the present invention is shown with elements numbered
as in Figure 1. In the embodiment of Figure 2, the combustion
products rise to the surface through a separate conduit 19 rather
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than through the wellbore surrounding the air conduit 10. The
combustion product return conduit and the combustion air conduit
are separate conduits connected at the bottom of the wellbore by a
crass-over 18. Fuel gas is provided through a fuel gas conduit 12
within the combustion product return conduit 19 and the combustion
air conduit 10. Alternatively, a single fuel gas conduit could be
used within either the combustion air conduit or the combustion
product return conduit, The combustion return conduit and the
combustion air conduit are cemented directly into the formation to
be heated 2 by a high temperature cement 7. If the combustion air
and combustion gases conduits are thick enough to not require
significant support from the cement, a graphite containing cement
can be utilized. This configuration should be considerably less
expensive to provide due to the absence of a large diameter casing
within the high temperature portion of the wellbore. The two
smaller conduits, when separated laterally within the wellbore, can
transfer heat into the formation more effectively than a single
conduit having the same surface area.
The flow conduits may be made from steel, high temperature
alloys such as INCONEL or INCOLOY or ceramics, depending upon the
operating temperatures and service life desired, Ceramics are
preferred as a material of construction for casings and flow
conduits of the present invention when injection of heat at
temperature levels above about 1100 °C are desired.
Referring to Figure 3, with elements numbered as in Figure l,
a preferred embodiment utilizing metal alloy flow conduits is
shown. The formation to be heated 1 below an overburden 2 is shown
penetrated by a wellbore 3 of about 30 cm in diameter. In this
embodiment, the wellbore is cased with a sacrificial casing 4 made
of a material such as carbon steel or stainless steel. Stainless
steel, although significantly more expensive than carbon steel, is
preferred when diatomite formations are subjected to the present
invention because the stainless steel will provide support for the
surrounding diatomite until the diatomite has at least partially
sintered and therefore increased in strength.
CA 02098266 2003-07-10
63293-3585
- 13 -
The casing is about 20 cm in diameter. The casing is cemented
into place using a high temperature cement 7 which forms an outer
perimeter of the flow channel through which combustion gases travel
up the wellbore. The cement is preferably one such as PERMACON, a
high alumina cement available from National Refractories, Inc. A
combustion air conduit 10 in this embodiment is made from an alloy
such as INCONEL 617 and is centralized within the casing. The
combustion air conduit could be, for example, a 7.5 to 10 cm
diameter tube. A fuel gas conduit 12 is centralized within the
combustion air conduit. The fuel gas conduit 12 can be made from an
alloy such as INCONEL 617 and could be about 2 cm in diameter.
Combustion occurs in the annulus between the fuel gas conduit,
and the combustion air conduit 10. At the lower end of the
.,
formation to be heated, within the wellbore, the combustion air
conduit is in communication with the annulus between the combustion
air conduit 10 and the casing. This annulus provides a flow path
for combustion products to travel back up the wellbore to the
surface.
The embodiment of Figure 3 provides for conventional
2p centralization of the flow conduits, and conventional replacement
of the fuel gas line and combustion air line if such replacement
becomes necessary.
Referring now to Figure 4, with elements numbered as in
Figure 1, a preferred embodiment of a burner is shown utilizing
stacked annular shaped ceramic bricks to form a combustion gas flow
conduit. A wellbore 3 is shown extending into a formation to be
heated 1 under an overburden 2. A casing of a sacrificial
material 4 is utilized to initially hold the ceramic bricks 20 in
place. The ceramic bricks can be about 7.5 cm wall thickness and
each about 1 to 3 m in height. The bricks may be made of a high
alumina ceramic material, and may be sealed together with a high
alumina mortar. A combustion air conduit 10 provides a flow path
for combustion air to the lower portion of the formation to be
heated. The combustion air conduit is open and in communication
with the annulus between the combustion air conduit and the ceramic
bricks near the bottom of the formation to be heated. A fuel gas
- 14 -
conduit 12 directs fuel gas into the volume defined by the casing
in increments through orifices 13 to provide for oxidation of the
fuel gas in relatively small increments. The fuel gas conduit and
the combustion air conduit may be ceramic if operating temperatures
are to be above about 1100 °C. If operating temperatures are to be
about 1100 °C or less, the flow conduits can be an alloy such as
INCONEL 617. The ceramic bricks are typically cemented into place
within the wellbore with a high temperature cement and preferably a
graphite containing high alumina cement.
Referring now to Figure S, another embodiment of a preferred
heat injector is shown with elements numbered as in Figure 1. This
embodiment is preferred when the heat injector is to be injecting
heat at temperatures of about 1100 °C to about 1371 °C. In this
embodiment, the combustion air conduit 10 the combustion gas
conduit 19 and the fuel gas conduit 12 are all initially
sacrificial materials cemented into place. The cement is a high
temperature cement. A high graphite content cement is not preferred
in this embodiment due to the lower strength of the high graphite
cements. A channel 22 near the bottom of the formation to be heated
provides communication between the combustion air conduit and the
combustion gas conduit. Communication between the fuel gas
conduit 12 and the combustion gas conduit and the combustion air
conduit is provided through conduits such as noble raetal tubes such
as platinum or platinum-plated tungsten 23 that may contain
orifices (not shown) to restrict flow of fuel gas into the larger
flow conduits. Combustion of the fuel gas occurs both in the down
flow combustion air conduit 10 and in the up flow combustion gases
conduit 19. Within the formation to be heated 1, the combustion gas
and the combustion air conduit are spaced as far apart as practical
in order to maximize the amount of heat which can be transfexred to
the formation at any maximum operating temperature.
The embodiment of Figure S could include a ceramic fuel gas
conduit or a sacrificial conduit which is eliminated prior to or
during initial operation, leaving the cement defining a conduit.
~~~~3~
- 15 -
The sacrificial conduit may be eliminated by, for example,
oxidation, melting, or milling. A plurality of fuel gas conduits
could optionally be provided. A plurality of fuel gas conduits
could provide redundancy, and could reduce the total length of
tubes 23 which are required. In the embodiment of Figure 5, the
wellbore 3 could be of about a 41 cm diameter within the formation
to be heated, and contain about a 7.5 to 10 cm internal diameter
combustion air conduit, a combustion gas conduit of about 7.5
to 10 cm diameter, and one or preferably two fuel gas conduits of
about 2 cm diameter. Orifices in the alloy tubes 23 are sized to
achieve a fuel gas floor that would result in a nearly uniform
temperature profile within the wellbore.
When ceramic materials are utilized for construction of the
heat injectors, the larger conduits (combustion air and combustion
product conduits) may initially be sacrificial materials such as
polymeric, fiberglass, carbon steel or stainless steel. The
sacrificial conduits can be cemented into place using high alumina
cements. The high alumina cement forms the conduit which remains in
place after the sacrificial materials are removed.
High alumina ceramic tubes are available that have tensile
strength sufficient to permit suspension of the conduits from a rig
at the surface. These ceramic conduits can be lowered into the
wellbore as sections are added at the surface. The sections can be
joined by mortar and held together by sacrificial clamps until the
mortar has cured. The ceramic tubes could also be held in place by
sacrificial pipes until they are cemented into place.
Cold start-up of a well heater of the present invention may
utilize combustion with a flame. Initial ignition may be
accomplished by injecting pyrophoric material, an electrical
igniter, a spark igniter, or temporarily lowering an electric
heater into the wellbore. The burner is preferably rapidly brought
to a temperature at which a flameless combustion is sustained to
minimize the time period at which a flame exists within the
wellbore. The rate of heating up the burner will typically be
limited by the thermal gradients the burner can tolerate.
- 16 -
Flameless combustion generally occurs when a reaction between
an oxidant stream and a fuel is not limited by mixing and the mixed
stream is at a temperature higher than the autoignition temperature
of the mixed stream. This is accomplished by avoiding high
temperatures at the point of mixing and by mixing relatively small
increments of fuel into the oxidant containing stream. The
existence of flame is evidenced by an illuminate interface between
unburned fuel and the combustion products. To avoid the creation of
a flame, the fuel and the oxidant are preferably heated to a
temperature of between about 815 °C and about 1371 °G prior to
mixing. The fuel is preferably mixed with the oxidant stream in
relatively small increments to enable more rapid mixing. For
example, enough fuel may be added in an increment to enable
combustion to raise the temperature of the stream by about 10 °C to
about 38 °C.
Although gas fuelled burners are preferred, electrical
resistance heaters could also be utilized to achieve the 900 °C or
higher heat injection temperatures of the present invention.
Electrical heating elements such as nickel and chromium alloys
could be utilized. Alternatively, a high graphite cement could be
used, and the cement could be utilized as a resistance element.
Figures 6 and 7 demonstrate the importance of injecting heat
at a high temperature level in a conductive heating hydrocarbon
recovery process. Figures 6 shows the hydrocarbon production
projections (in per cent of the oil in place on the vertical axis)
as a function of time (in years on the horizontal axis) for heat
injector temperature levels of 815 °C, 1093 °C and 1371
°C. In
Figure 6, hydrocarbon recovery for temperature levels of 815 °C,
1093 °C and 1371 °C are shown as lines A, B and C respectively.
Figure 7 shows heat injection rates (in W/m on the vertical
axis) as a function of time (in years on the horizontal axis). In
Figure 7, heat injection rates for temperature levels of 815 °C,
1093 °C and 1371 °C are shown as lines D, E and F respectively.
The well pattern used for estimates of Figures 6 and 7
included production wells placed in a 5000 m2 square pattern, the
- 17
square pattern being at right angles with the direction of the
minimum principal stress within the hydrocarbon-containing
formation. Production wells are therefore separated by about 100 m.
Optimal distances between production wells will vary
significantly depending upon the size of fracture which can be
imparted into the formation, the formation permeability, the cost
of providing producer wells and the cost of providing fractures.
Generally, the producer wells wall be separated by between
about 30 and 100 m. In the case of fractured producer wells, the
fractures will generally be separated by about 30 to 100 m, and the
fractures will extend to about the tips of the fractures from
adjacent wells.
Figures 6 and 7 are based on heat injection wells situated in
rows between the production wells, the rows being essentially
perpendicular to the direction of the minimum principal stress of
the formation. Seven heat injection wells are provided for each
production well. Heat injectors are therefore about 15 m apart. The
formation properties were assumed to be similar to those of a
diatomite formation.
Heat injection wells will generally be more than about 5 m
apart, and preferably about 6 to about 30 m apart. Greater
separation results in a slow recovery of hydrocarbons from the
formation whereas closer spacing results in excessive heat injector
initial investment. Because heat transfer from the heat injection
well in the vicinity of the injection well generally limits the
rate of heat injection, more heat injection wells than producer
wells are generally provided. Typically, about two to about nine
heat injection wells will be provided for each producer well. For a
diatomite formation, about six to about seven heat injection wells
per producer well are preferred.
Figures 6 and 7 are based on the formation being fractured
from the production wells, creating fractures that run essentially
parallel to the rows of heat injection wells. When the hydrocarbon-
containing formation has a permeability of less than about
~~~3~~~~~~
is -
20 millidarcys, the formation is preferably fractured from the
production wells.
Fracturing of production wells in this heat injection process
is another inventive aspect of the present process when applied to
diatomite formations. Typically, thermal recovery processes will
significantly increase compressive forces in formation rocks due to
thermal expansion of the rocks. This increase in compressive forces
will typically close fractures. Diatomite rocks behave differently.
Heating the diatomite rocks to temperatures above about 150 °C
will result in some shrinkage of the rock. This shrinkage is most
pronounced between about 900 °C and about 1000 °C, but is
evident
at considerably lower temperatures. This shrinkage indicates that
fractures within diatomite formations, if open when heat injection
is initiated, will tend to stay open as the formation is heated.
Open fractures increases the surface area through which
recovered hydrocarbons can pass to enter the production wellbore.
Arrangement of rows of heat injection wells between fractures
minimizes the distance recovered hydrocarbons must travel before
being captured by the production well.
For Figures 6 and 7, heat was assumed to be transferred from a
borehole with an effective radius of 13 cm. Diatomite sintering and
the use of highly heat conductive cement in the borehole generates
a relatively highly heat conductive zone around the borehole. This
zone is 41 cm in diameter for the 1093 °C and 1371 °C cases. It
is
30 cm in diameter for the 815 °C case due to the lack of
significant sintering at this lower temperature. The smaller zone
of relatively high heat conductivity along with the lower
temperature level of heat injection contribute to the lower and
slower hydrocarbon recoveries for the 815 °C case.
The hydrocarbon-containing formation was a diatomite formation
having an initial porosity of about 50$ and an initial water
content of about twenty percent by volume. The hydrocarbons in the
formation were a 28 gravity crude oil. The heat injector wellbores
assumed for Figures 6 and 7 were of 41 cm in diameter with the
annulus between the burner and the formation filled with a cement
- 19 -
that has a heat conductivity of four times the heat conductivity of
diatomite. The heat conductivity of the diatomite formation was
assumed to be about 0.97 J/m/°C/s. The formation was sufficiently
thick that heat losses from the top and bottom of the formation are
negligible.
Heat injection begins at time equal to zero in Figures 6
and 7. These cases represent, respectively, prior art temperature
level of heat injection, high temperature metal alloy burners, and
very high temperature ceramic type burners. The three cases are
represented on Figure 6 by lines A, B and C respectively. It can be
seen from Figure 6 that initial hydrocarbon production begins
between about two and three years from initial heat injection for
the latter two cases. Production is essentially complete after
about thirteen and ten years for the 1093 °C and 1371 °C cases
respectively. The 815 °C case does not begin to produce significant
amounts of hydrocarbons until heat has been injected for about
seven years and takes more than twenty years to produce the
formation hydrocarbons.
Figure 7 is a plot of the heat injection rates required to
achieve the three cases described above. It can be seen that heat
injection rates must be decreased over time as the formation near
the wellbore becomes hotter. Average rates of heat injection are
about 1640 W/m for the 1371 °C case, about 1310 W/m for the 1093
°C
case and about 510 W/m for the 815 °C case.
At temperatures above about 900 °C diatomite rock sinters,
decreasing its porosity and increasing its grain density. '!'his
results in an increased bulk density, thermal conductivity, and
strength. This phenomenon occurs near the wellbore and causes an
enhanced heat injectivity in the practice of the present invention.
The very high temperatures also increase the hydrogen content
in the near wellbore region which further improves the thermal
conductivity.
Heating diatomite rock to temperatures between about 200 °C
and 500 °C does not cause sintering but increases the Young's
modulus of the rock by a factor of 2 to 3. This takes place in most
F~a~~Oa~~)~~
of the formation by the end of the heat injection phase of the
present process.
The overall strengthening of the rock resulting from the
present process results in reduced subsidence when the pore
pressure drops due to continued fluid withdrawals.
Considerably more capital investment can be justified based on
the expected hydrocarbon production of the 1371 °C and 1093 °C
cases than the 815 °C case due to the long time period before
hydrocarbon production is realized in the later case.
Figure 8 is a plot of calculated temperatures (in °C on the
vertical axis) as a function of distance from a mixing point (in
meters on the horizontal axis) in a cylindrical combustion chamber.
The cylindrical combustion chamber is of an 20 cm internal
diameter, and a flow of 0.104 standard cubic meter per second
(standard at 15 °C and one atmosphere pressure) of combustion gases
containing three percent by volume of oxygen is mixed with enough
methane that combustion of the methane would increase the
temperature of the stream by 5 °C. Both the methane and the
combustion gases are initially at the same temperature. Mixing of
the methane and the combustion gases is assumed to be rapid. Heat
is removed from the combustion chamber at a rate of about 1 230 W
per m of length. Temperature profiles shown as lines a through h
represent temperature profiles for gases starting at temperatures
of 760 °C through 1150 °C in 50 °C respectively.
Figure 8 demonstrates that under these conditions, the
reaction between methane and oxygen occurs at a useful rate.
Flameless at a temperature less than about 815 °C would
require a longer residence time than that provided by an 20 cm
diameter chamber at a low pressure in order to provide heat to a
formation at a rate greater than about 1 230 W/m. Reaction of the
fuel and oxygen is very quick at 1150 °C.
Flameless combustion was demonstrated by injection of natural
gas into a stream of exhaust gasses in an amount sufficient for
combustion to raise the temperature of the gas stream by about
~(~~~~~~~~-
- 21 -
25 °C. The exhaust gas stream contained about 3.6 molar percent
oxygen and was at a temperature of about 840 °C. The combined
stream was analyzed for carbon monoxide and hydrocarbons at a point
downstream of the mixing. The residence time was about 0.3 seconds.
About 40 ppm carbon monoxide was detected in the sample but no
hydrocarbons were detected. The combustion was flameless.
Referring to Figure 9, a plan view of a preferred well pattern
for the practice of the present invention is shown. Heat injection
wells 81 are shown in rows along a vertical plane of minimum stress
within a hydrocarbon-containing formation. Hydrocarbon production
wells 82 are spaced at about uniform intervals between the rows of
heat injection wells. The productions wells have been fractured by
known hydraulic fracturing means forming fractures 83 from the
wellbores. The fractures preferably extend in tip to tip fashion.
The heat injection wells, could in a further refinement, be
staggered along a line between the hydrocarbon production wells.
Staggering the heat injection wells increases the distance
between the heat injection wells and therefore decreases the effect
of one on another early in the process of heating the formation.
