Oil recovery process

A process to recover oil is provided wherein an oil containing subterranean formation is heated by conductive heat transfer from heat injectors operating at temperatures above 900.degree. C. The high temperature levels of this process result in high recoveries of initial oil in place, and recovery of the oil within a short time period. This process is particularly applicable to diatomite formations that have low permeabilities.

RELATED PATENTS 
This patent is related to U.S. patent application Ser. No. 896,861 filed 
Jun. 12, 1992, now U.S. Pat. No. 5,255,742, and Ser. No. 897,641, filed 
Jun. 12, 1992, now U.S. Pat. No. 5,226,961. 
FIELD OF THE INVENTION 
This invention relates to an improved method and apparatus for recovering 
hydrocarbons from hydrocarbon containing subterranean formations. 
BACKGROUND TO THE INVENTION 
U.S. Patent Nos. 4,640,352 and 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 oil 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 uniform thermal conductivities and specific 
heats. Production of oil in a thermal conduction process is by pressure 
drive, vaporization and thermal expansion of oil and water trapped within 
the pores of the formation rock. Oil migrates through small fractures 
created by the expansion and vaporization of the oil and water. 
Patent '352 discloses 600.degree. C. to 900.degree. C. as a preferred 
temperature range for heat injection for the thermal conduction process. 
Electrical resistance is disclosed as a 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 240 watts per foot. This rate of heat input would result in 
an injection temperature within the temperature range of about 600.degree. 
C. to 900.degree. C. 
This heat conduction process has been known for a relatively long time, yet 
can not be practiced 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 oil 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 U.S. Pat. No. 2,902,270 and 
Swedish Patent 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.degree. C. radiant heat source. The heaters are therefore more 
expensive than a comparable heater without flames. The heater of Swedish 
Patent 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.degree. C. 
about 100 feet of wellbore would be sufficient to preheat the 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 FIG. 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. 
FIG. 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. 
U.S. Pat. Nos. 3,113,623 and 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 fifty feet thick and below only about fifteen feet 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 U.S. Pat. Nos. 2,923,535; 3,095,031; 3,880,235; 4,079,784; and 
4,137,968. 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 required 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 oil 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. 
SUMMARY OF THE INVENTION 
These and other objects are accomplished by a method comprising the steps 
of: providing heat injection means extending essentially through a 
hydrocarbon containing subterranean formation, the heat injection means 
capable of injecting heat at a temperature level of above about 
900.degree. 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.degree. 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 oil, 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 oil 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 oil 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, formations 
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 are 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. 
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 to develop permeability by fracturing and pyrolysis 
of solids upon heating may also be subjected to the present process.

DETAILED DESCRIPTION OF THE 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.degree. C. and preferably above about 1000C. 
Gas fueled 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. 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 flameless combustion of fuel gas at temperature levels 
of about 900.degree. C. to about 1100.degree. C. may be fabricated from 
high temperature alloys such as, for example, INCONEL 617, INCOLOY 800HT, 
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.degree. C. to about 
1400.degree. C. are generally high alumina content ceramics. Other 
ceramics that may be useful include chrome oxide, zirconia oxide, and 
magnesium oxide based ceramics. National Refractories and Minerals, Inc., 
Livermore, Calif.; A. P. Green Industries, Inc., Mexico, Mo.; 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.degree. C. and about 
1400.degree. 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.degree. C. to 100.degree. C. temperature 
rise in the combustion gas stream due to the combustion of the fuel. 
Referring to FIG. 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. A wellbore, 3, extends through the overburden and to 
near the bottom of the formation to be heated. In the embodiment shown in 
FIG. 1, the wellbore is cased with a casing, 4. The lower portion of the 
wellbore may be cemented with a cement, 7, having characteristics suitable 
for withstanding elevated temperatures and transferring heat. A cement 
which is a good thermal insulator, 8, 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 U.S. Pat. Nos. 3,507,332 and 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 FIG. 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 4 
and about 8 inches 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 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 aluminum 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 of 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 utilization 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. 
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 injection of fuel gas and oxidant suppressant are shown in 
FIG. 1 as 16 and 17 respectively. The carbon formation suppressant may be 
carbon 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: 
EQU CH4.fwdarw.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: 
EQU CO2+C.fwdarw.2CO 
Steam suppresses carbon formation by the following reactions: 
EQU H2O+C.fwdarw.CO+H2 
EQU 2H2O+C.fwdarw.CO2+2H2 
The carbon dioxide and the carbon monoxide remain in equilibrium at 
elevated temperatures according to the shift gas reaction: 
EQU CO+H2O.rarw..fwdarw.CO2+2H2 
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 2500.degree. F. (1371.degree. 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 suppressant is 
additionally beneficial because it lowers combustion rates and reduces 
peak temperatures. 
Referring now to FIG. 2, an alternative apparatus capable of carrying out 
the present invention is shown with elements numbered as in FIG. 1. In the 
embodiment of FIG. 2, the combustion products rise to the surface through 
a separate conduit, 19, rather 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 cross-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.degree. C. are 
desired. 
Referring to FIG. 3, with elements numbered as in FIG. 1, 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 twelve inches 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. 
The casing is about eight inches 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 three to four inch diameter tube. A fuel gas conduit, 12, is 
centralized within the combustion air conduit. The fuel gas conduit can be 
made from an alloy such as INCONEL 617 and could be about three quarters 
of an inch in diameter. Combustion occurs in the annulus between the fuel 
gas conduit, and the combustion air conduit, 12. 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 FIG. 3 provides for conventional 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 FIG. 4, with elements numbered as in FIG. 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 three inches 
wall thickness and each about five to ten feet 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 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.degree. C. If 
operating temperatures are to be about 1100.degree. 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 FIG. 5, another embodiment of a preferred heat injector is 
shown with elements numbered as in FIG. 1. This embodiment is preferred 
when the heat injector is to be injecting heat at temperatures of about 
1100.degree. C. to about 1371.degree. C. In this embodiment, the 
combustion air conduit, 10, the combustion gas conduit, 19, and the fuel 
gases 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 metal 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 transferred to the formation at any maximum operating temperature. 
The embodiment of FIG. 5 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. 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 FIG. 5, the 
wellbore, 3, could be of about a sixteen inch diameter within the 
formation to be heated, and contain about a three to four inch internal 
diameter combustion air conduit, a combustion gas conduit of about three 
to about four inch diameter, and one or preferably two fuel gas conduits 
of about three quarters inch diameter. Orifices in the alloy tubes, 23, 
are sized to achieve a fuel gas flow 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. 
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.degree. C. and about 1371.degree. C. 
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.degree. C. to about 38.degree. C. 
Although gas fueled burners are preferred, electrical resistance heaters 
could also be utilized to achieve the 900.degree. 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. 
FIGS. 6 and 7 demonstrate the importance of injecting heat at a high 
temperature level in a conductive heating oil recovery process. FIGS. 6 
and 7 are, respectively, oil production projections and heat injection 
rates as a function of time for heat injector temperature levels of 
815.degree. C. (1500.degree. F.), 1093.degree. C. (2000.degree. F.) and 
1371.degree. C. (2500.degree. F.). In FIG. 6, oil recovery for temperature 
levels of 1500.degree. F., 2000.degree. F. and 2500.degree. F. are shown 
as lines A, B and C respectively. In FIG. 7, heat injection rates for 
temperature levels of 815.degree. C., 1093.degree. C. and 1371.degree. C. 
are shown as lines D, E and F respectively. 
The well pattern used for estimates of FIGS. 7 and 8 included production 
wells placed in a 1.25 acre square pattern, the 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 330 feet. 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 will be separated by between about 100 and about 300 feet. 
In the case of fractured producer wells, the fractures will generally be 
separated by about 100 to about 300 feet, and the fractures will extend to 
about the tips of the fractures from adjacent wells. 
FIGS. 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 47 feet apart. The formation properties were assumed to be 
similar to those of a diatomite formation. 
Heat injection wells will generally be more than about 15 feet apart, and 
preferably about 20 to about 100 feet apart. Greater separation results in 
a slow recovery of oil 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. 
FIGS. 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 20 mdarcys, 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.degree. C. will result in some shrinkage 
of the rock. This shrinkage is most pronounced between about 900.degree. 
C. and about 1000.degree. 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 FIGS. 6 and 7, heat was assumed to be transferred from a borehole with 
an effective radius of five inches. 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 sixteen 
inches in diameter for the 1093.degree. C. and 1371.degree. C. cases. It 
is 12 inches in diameter for the 815.degree. 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 oil recoveries for 
the 815.degree. C. case. 
The oil containing formation was a diatomite formation having an initial 
porosity of about 50% and an initial water content of about twenty percent 
by volume. Oil in the formation was 28 gravity crude oil. The heat 
injector wellbores assumed for FIGS. 6 and 7 were of sixteen inches in 
diameter with the annulus between the burner and the formation filled with 
a cement 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 2.3.times.10.sup.-3 cal/(cm-sec-C). 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 FIGS. 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 FIG. 6 by lines A, B and 
C respectively. It can be seen from FIG. 6 that initial oil 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.degree. C. and 1371.degree. C. cases 
respectively. The 815.degree. C. case does not begin to produce 
significant amounts of oil until heat has been injected for about seven 
years and takes more than twenty years to produce the formation oil. 
FIG. 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 500 watts per foot for the 
1371.degree. C. case, about 400 watts per foot for the 1093.degree. C. 
case and about 155 watts per foot for the 815.degree. C. case. 
At temperatures above about 900.degree. C. diatomite rock sinters, 
decreasing its porosity and increasing its grain density. This 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.degree. C. and 
500.degree. 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 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 
oil production of the 1371.degree. C. and 1093.degree. C. cases than the 
815.degree. C. case due to the long time period before oil production is 
realized in the later case. 
Referring to FIG. 8, 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-bearing formation. Oil 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 oil 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.