Combined surface and in situ tar sand bitumen production

In-situ combustion of tar sand formations is improved by introducing into an unminable tar sand formation prior to initiation of in-situ combustion hydrogen sulfide produced from upgrading tar sands from a minable tar sand formation in an area proximate the area of the unminable formation. The stream of hydrogen sulfide may contain a small proportion of hydrocarbons condensible at temperature and pressure conditions of the unminable formation. The improvement is applicable to both forward and reverse in-situ combustion processes.

BACKGROUND OF THE INVENTION 
The present invention is directed to a method for recovering hydrocarbons 
(bitumen) from tar sand deposits. According to the process, hydrogen 
sulfide is generated by upgrading bitumen produced from minable tar sands 
and hydrocarbons are recovered from an unminable subterranean tar sand 
formation in an area proximate to the area of the hydrogen sulfide 
recovery by utilizing an improved in-situ combustion operation wherein the 
hydrogen sulfide is injected into the subterranean formation prior to 
commencement of combustion. 
Increasing worldwide demand for petroleum products, combined with 
continuously increasing prices for petroleum and products recovered 
therefrom, has prompted a renewed interest in the sources of hydrocarbons 
which are less accessible than crude oil of the Middle East and other 
countries. One of the largest deposits of such sources of hydrocarbons 
comprises tar sands deposits found in Northern Alberta, Canada, and in the 
Midwest States of the United States. While the estimated deposits of 
hydrocarbons contained in tar sands are enormous (e.g., the estimated 
total of the deposits in Alberta, Canada is 250 billion barrels of 
synthetic crude equivalent), only a small proportion of such deposits can 
be recovered by currently available mining technologies (e.g., by strip 
mining). For example, in 1974 it was estimated that not more than about 10 
percent of the then estimated 250 billion barrels of synthetic crude 
equivalent of deposits in Alberta, Canada was recoverable by the then 
available mining technologies. (See SYNTHETIC FUELS, March 1974, Pages 3-1 
through 3-14). The remaining about 90 percent of the deposits must be 
recovered by various in-situ techniques such as electrical resistance 
heating, steam injection and in-situ forward and reverse combustion. In 
addition to tar sands, heavy, viscous crudes and crudes from partially 
depleted reservoirs are also recoverable by in-situ production techniques. 
While details of operating of all of such in-situ techniques vary, a common 
objective thereof is to lower the viscosity of the hydrocarbon deposits to 
the point where they can be pumped to the surface of the formation with 
equipment normally available at the formation site. 
Of the aforementioned in-situ recovery methods, in-situ combustion (both 
forward and reverse) appears to be the most promising method of 
economically recovering large amounts of hydrocarbon deposits with 
currently available technology. The attractiveness of the in-situ 
combustion methods arises primarily from the fact that it requires 
relatively little energy necessary for sustaining combustion of the 
hydrocarbon deposits. In contradistinction, other in-situ techniques, such 
as electrical resistance heating and steam injection require considerable 
amounts of energy, e.g., to heat the steam at the surface before it is 
injected into the petroliferous formation. 
Conventional in-situ combustion involves drilling of at least two 
substantially vertical wells into the formation, the wells being separated 
by a horizontal distance within the formation. One of the wells is 
designated an injection well, and the other a production well. The 
recovery of hydrocarbons is accomplished by raising the temperature around 
a bore hole to the combustion temperature of the petroliferous deposit 
with some type of a conventional down hole heater/burner apparatus, and 
then supporting the combustion by injecting an oxidizing gas, e.g., oxygen 
or air into the formation. There are two basic processes of in-situ 
combustion, viz., forward and reverse combustion. Forward combustion is 
initiated at the oxidant injection well and the combustion front 
propagates toward the production well. Reverse combustion is initiated at 
the production well and the combustion front propagates toward the oxidant 
injection well. Hydrocarbon vapors produced during the combustion process 
are recovered at the surface of the formation and stored in appropriate 
containers. The combustion is conducted at a temperature not to exceed 
1500.degree. F. for about 12 months until the viscosity of oil deposits is 
reduced to 700-800 cp, generally considered necessary for pumping the oil 
to the surface of the formation. Further details of forward and reverse 
in-situ combustion techniques are set forth in SYNTHETIC FUELS, March 
1974, pages 3-4 through 3-14, and in THE TAR SANDS OF CANADA by F. W. 
Camp, pages 27-34, Cameron Engineers, Inc., Denver, Colo., 2nd Edition 
(1974), the entire contents of which are incorporated herein by reference. 
Modified in-situ combustion techniques using a combination of oxygen and 
other chemical substances are also known in the art. For example, Heilman 
et al., U.S. Pat. No. 2,718,263 uses a mixture of oxygen-containing gas 
and fuel to generate heat in the formation, and Elzinga, U.S. Pat. No. 
3,087,541, injects fuel into the formation only after the combustion has 
started. Both of these modified in-situ prior art combustion processes 
uses fuels injected externally into the formation either simultaneously 
with oxygen or after the injection of oxygen to control the direction of 
speed of propagation of the combustion front. 
However, heretofore practiced in-situ combustion techniques have resulted 
in a relatively low rate of recovery of available hydrocarbons from 
subterranean petroliferous formations. For example, the rates of recovery 
have been reported to be less than about 50 percent of the total deposits 
of tar sands, e.g., SYNTHETIC FUELS, March 1974, pages 3-4 through 3-14. 
Tar sand formations with an overburden greater than 500 feet are not 
amenable to recovery by surface mining. Such formations present a problem 
as to ways and means of economic recovery. The techniques available for 
such recovery are limited and are restricted to in situ techniques. Many 
in situ techniques have been considered such as electrical resistance 
heating, steam injection and fire flooding. Inherent problems exist in all 
in situ methods, for example, poor volumetric sweep, fluid displacement 
profiles in steam injection and difficulty in starting combustion and 
maintaining design temperatures in fire flooding. Other tar sand 
formations that do not have such a thick overburden are amenable to 
surface mining techniques. Usually the overburden is removed and the 
underlying desirable tar sand is scooped up and processed for hydrocarbon 
recovery. Many procedures have been described for this separation of which 
the Clark Hot Water process is typical. 
As recovered the bitumen is not usuable and is usually upgraded by delayed 
or fluid coking. This coking step produces a liquid product which is 
usually fractionated into three products. Each of these products is 
further upgraded by hydrogen treatment. As a result of this upgrading 
step, the sulfur usually contained in the products is converted to 
hydrogen sulfide. 
Hydrogen sulfide has very limited or no use as a product and usually is 
converted to elemental sulfur by way of the Claus process. In certain 
distant locations it may not be possible to sell the sulfur and a large 
inventory of unsold sulfur could result. It is thus desirable to minimize 
the amount of sulfur generated on such sites. 
Thus, the location of a tar sand recovery plant and its upgrading 
facilities could be used to advantage so as to minimize the production of 
sulfur. By selecting a tar sand deposit amenable to surface recovery 
adjacent to a deposit which is not and which requires the use of in situ 
production techniques, this desirable minimization of the production of 
sulfur could be achieved. 
In my copending application, Ser. No. 260,521, filed May 4, 1981, there is 
disclosed an improved in-situ combustion process for the recovery of 
viscous oil from tar sand formations wherein a combustible gas such as a 
relatively light hydrocarbon gas having a condensation point of 
-173.degree. C. to -43.degree. C. or hydrogen sulfide is injected into the 
formation prior to the initiation of combustion. 
The present invention is an improvement of the process disclosed in my 
copending application described above wherein the hydrogen sulfide 
injected into the formation prior to initiation of in-situ combustion is 
produced on site as a by-product in the upgrading of minable tar sands. 
Therefore, the present invention allows recovery of difficult to produce 
tar sand formations and at the same time uses available hydrogen sulfide 
thus minimizing the amount of sulfur produced as a by-product of hydrogen 
upgrading of products produced from minable tar sands. 
SUMMARY OF THE INVENTION 
The invention is a method for the recovery of hydrocarbons (bitumen) from a 
tar sand deposit having a minable tar sand formation and an unminable tar 
sand formation in an area proximate to the area of the minable formation, 
said unminable tar sand formation penetrated by at least one injection 
well and at least one spaced-apart production well, said injection well 
and production well being in fluid communication with a substantial 
portion of the unminable formation, comprising mining the tar sands from 
the minable formation, conveying the mined tar sands to a processing 
operation wherein the tar sands are processed to recover bitumen and 
by-product hydrogen sulfide, injecting a predetermined amount of said 
hydrogen sulfide into said unminable tar sand formation via said injection 
well, initiating an in-situ combustion reaction in the unminable formation 
by injecting an oxygen containing gas into the injection well; and 
continuing to inject an oxygen containing gas into the injection well to 
propagate the combustion zone through the formation to stimulate recovery 
of hydrocarbons from the formation via the production well.

DESCRIPTION OF PREFERRED EMBODIMENTS 
The present invention involves a process for recovering hydrocarbons 
(bitumen) from a tar sand deposit having two types of tar sand formations, 
a minable tar sand deposit in an area proximate to a tar sand deposit 
which is not minable and which requires the use of in situ production 
technique to recover hydrocarbons thereform. The mined tar sands are 
processed on site by various conventional processes such as a "hot water 
process" to produce a bitumen product that is upgraded by delayed or fluid 
coking and further upgrading the liquid product produced from the coking 
step by hydrogen treatment to produce an upgraded oil product and a 
hydrogen sulfide by-product. Processes of this character are described in 
Hydrocarbon Processing Vol. 61, September 1982, pages 108-139, 140-154, 
and 100-163, the disclosure of which is hereby incorporated by reference. 
The hydrogen sulfide is recovered and used in conjunction with an in-situ 
combustion operation to recover hydrocarbons from the adjacent tar sand 
formation that are not amenable to recovery by surface mining. For the 
purpose of this invention an unminable formation is a formation with an 
overburden greater than 500 feet. 
In the recovery of hydrocarbons (bitumen) by the in-situ combustion phase 
of the present invention, the subterranean tar sand formation is 
penetrated by at least one injection well and at last one spaced-apart 
production well, both wells being in fluid communication with a 
substantial portion of the oil-containing formation. The hydrogen sulfide 
recovered from upgrading minable tar sands described above is injected 
into the lower half of the formation via the injection well, preferably 
not more than 1 percent to 40 percent of the length of the formation, and 
most preferably 3 percent to 25 percent of the height of the formation, 
measured from the bottom thereof. In this connection, the height of the 
petroliferous formation is defined as the total thickness of the 
formation, measured from the beginning point below the surface of the 
earth where the amount of petroliferous materials in the formation is at 
least 80 percent, preferably 100 percent, to the point above said 
beginning point of the formation wherein the relative amount of 
petroliferous material in the formation is at least 95 percent, preferably 
100 percent. 
The rate of introduction of the hydrogen sulfide into the formation will 
vary, depending on the formation wherein the process is practiced. 
Generally speaking, the rate of introduction of the gas and the time 
realized for the introduction thereof into the formation will be such that 
the injection will continue until the formation contains at least 30 cu. 
ft. of hydrogen sulfide per barrel of oil equivalents present in the 
formation, preferably 30 to 1000 cu ft. of hydrogen sulfide per barrel of 
oil equivalents present in the formation. Most preferably, the formation 
will be relatively substantially saturated with the hydrogen sulfide 
injected therein. In this connection, a point of relative saturation of 
the formation with the hydrogen sulfide is defined as the point at which 
the formation cannot absorb appreciable additional quantities of hydrogen 
sulfide beyond those which have already been absorbed. 
The pressure under which the hydrogen sulfide is introduced into the 
formation will be determined by the depth of the formation below the 
surface of the earth and by the existing pressure at that depth. For 
example, in the case of a tar sand deposit the hydrogen sulfide is 
introduced under a pressure of 20 atm to 100 atm, preferably 60 atm to 80 
atm, and most preferably 65 atm to 70 atm, and at a temperature of 
-40.degree. C. to 100.degree. C., preferably 0.degree. C. to 60.degree. 
C., and most preferably 25.degree. C. to 35.degree. C. 
In an alternative embodiment, the hydrogen sulfide may contain a small 
proportion (1 percent to 10 percent by volume) of compounds which condense 
at the temperature and pressure conditions of the formation. The condensed 
compounds (e.g., methylamine, ethylamine, t-butylamine and hydrocarbons) 
have a condensation point of not more than 100.degree. C. at ambient 
pressure and they are dissolved in the petroliferous deposits facilitating 
the combustion of the latter during the subsequent in-situ combustion. If 
the condensable compounds used for such purpose are hydrocarbons, they 
must have a condensation point of at most 100.degree. C. under ambient 
pressure conditions of about one atmosphere. Suitable condensable 
hydrocarbons for such purpose are: all hydrocarbons of C.sub.4 to C.sub.7, 
such as alkanes, alkenes and aromatics, e.g., n-butane, isobutane, 
n-pentane, isopentane, hexane, all of its isomers and heptane and all of 
its isomers, benzene, and toluene, preferably normal pentane and 
isopentane, hexane, heptane and all of the isomers thereof. 
The amount of condensable compounds present in the hydrogen sulfide 
injected into the formation is 1 percent to 10 percent, preferably 2 
percent to 8 percent, and most preferably 3 percent to 5 percent by 
volume. The condensable compounds dissolve relatively easily in the 
formation, thereby aiding in the combustion thereof when in-situ 
combustion is initiated. When the condensable compounds are hydrocarbons, 
their viscosity should be 0.01 centipoise (cp) to 0.5 centipoise at 
40.degree. C. Preferably, the viscosity should be 0.05 centipoise to 0.3 
centipoise, and most preferably 0.10 centipoise to 0.15 centipoise at 
40.degree. C. The density of the condensable hydrocarbons should be 0.6 to 
0.75 g/cm.sup.3, preferably 0.62 to 0.67 g/cm.sup.3, most preferably 0.65 
g/cm.sup.3. 
The relatively easily condensable hydrocarbons present in the gaseous 
stream can either comprise a single homogeneous hydrocarbon substance 
encompassed by any one of the generic groups enumerated above, or they can 
be a mixture of any of such substances, so long as the relative 
proportions of the individual components of such mixtures are such that 
the condensation point, the viscosity, the density and other properties of 
the mixture fall within the range of the respective properties of the 
relatively easily condensable hydrocarbons specified above. 
After the injection of the hydrogen sulfide, either with or without 
condensable compounds, is completed, the in-situ combustion proceeds in 
the usual manner, i.e., the temperature of the formation is brought to or 
near the combustion temperature and an oxygen containing gas such as 
oxygen, air, or oxygen enriched air is injected into the formation via the 
injection well in a conventional manner as described in S. M. Farouq Ali, 
A Current Appraisal of In-Situ Combustion Field Tests, THE JOURNAL OF 
PETROLEUM TECHNOLOGY, pp. 477-486, (April, 1972), the entire contents of 
which are incorporated herein by reference. Injection of the oxygen 
containing gas is continued to propagate the combustion zone through the 
formation to stimulate recovery of hydrocarbons from the formation via the 
production well. 
The autoignition temperature of hydrogen sulfide (H.sub.2 S) is about 
260.degree. C. Accordingly, ignition of the subterranean petroliferous 
formation can be initiated at relatively low formation temperatures. 
Once the combustion of the petroliferous material has begun, the hydrogen 
sulfide previously introduced into the formation and which preferably 
saturates the formation, aids in the combustion, thereby markedly 
accelerating the entire combustion process and increasing the yield of 
recoverable hydrocarbons. 
From the foregoing specification one skilled in the art can readily 
ascertain the essential features of this invention and without departing 
from the spirit and scope thereof can adopt it to various diverse 
applications.