|Publication number||US3838738 A|
|Publication date||Oct 1, 1974|
|Filing date||May 4, 1973|
|Priority date||May 4, 1973|
|Also published as||CA1001067A, CA1001067A1, DE2421581A1, DE2421581C2|
|Publication number||US 3838738 A, US 3838738A, US-A-3838738, US3838738 A, US3838738A|
|Inventors||Allen J, Redford D|
|Original Assignee||Allen J, Redford D, Texaco Exploration Ca Ltd, Texaco Inc|
|Export Citation||BiBTeX, EndNote, RefMan|
|Patent Citations (10), Referenced by (68), Classifications (6)|
|External Links: USPTO, USPTO Assignment, Espacenet|
United States Patent 1191 Redford et al.
[ METHOD FOR RECOVERING PETROLEUM 1 Oct. 1, 1974 3,500,916 3/1970 Der Knaap et a1. [66/272 FROM VISCOUS PETRQLEUM 3,500,917 3/1970 Lehner et a1. 166/272 3,513,914 5/1970 Vogel 166/271 CONTAINING FORMATIONS INCLUDING 1 3,729,053 4 1973 F 166 273 TAR SANDS i  Inventors: David Arthur Redford, Fort Primary Examiner-James A. Leppink Sasketchwan, Alberta, Canada; Attorney, Agent, or Firm-T. l-l. Whaley; C. G. Ries Joseph Columbus Allen, Bellaire, Tex.  ABSTRACT  Assignees: Texaco Explorati n C ad 1,, Petroleum may be recovered from viscous petroleum Calgary, Alb rta, Ca d b id containing formations including tar sand deposits by Redford; Texaco Inc., New York, first creating a fluid communication path low in the NY, by aid All formation, followed by injecting a heated fluid, aqueous or nonaqueous, into the fluid communication  May 1973 path, followed by injecting a'volatile solvent such as  Appl, No 357,425 carbon disulfide, benzene or toluene into the preheated flow path and continuing injecting the heating fluid. The low boiling point solvent is vaporized and  US. CL. 166/271, 166/272 moves upward into the formation where it dissolves  Int. Cl E2lb 43/26, E2lb 43/24 petroleum loses heat and condenses thereafter flow Fleld of Search down y g dissolved bitumen with it into h preheated flow path. The low boiling point solvent ef-  References and fectively cycles or refluxes within the formation and is UNITED STATES PATENTS not produced to the surface of the earth. Bitumen is 2,708,481 5/1955 Allen 166/268 transferred from the volatile solvent to the heating 2,910,123 111/1959 ns et 1 166/27l fluid continually passing through the communication 2,974,937 3/1961 166/272 path and bitumen and heating are recovered to- 3,003,554 10/1961 Craig, Jr. et al. 166/274 gather as a mixture or solution 3,221,813 12/1965 Closmann et al..... 166/271 i i 3,396,791 8/1968 Van Meurs et al. 166/272 28 Claims, 1 Drawing Figure '75 J70??? 0/? P/F'OCfJJ/NG V V 0, & 0 5, W a s \C 7 (C3 VAPOR) 1 I (cs z/auw) 3 5 a) av s- METHOD FOR RECOVERING PETROLEUM FROM VISCOUS PETROLEUM CONTAINING FORMATIONS INCLUDING TAR SANDS BACKGROUND OF THE INVENTION 1. Field of the Invention This invention pertains to an oil recovery method, and more specifically to a method for recovering oil or petroleum from a subterranean viscous petroleum con taining formation such as a tar sand deposit.
2. Description of the Prior Art There are known to exist throughout the world many subterranean petroleum containing formations from which the petroleum cannot be recovered by conventional means because of the relatively high viscosity thereof. The best known of such viscous petroleum containing formations are the so-called tar sands or bituminous sand deposits. The largest and most famous such deposit is in the Athabasca area in the northeastern part of the province of Alberta, Canada, which is known to contain over 700 billion barrels of petroleum. Other extensive deposits are known to exist in the western part of the United States, and Venezuela, and lesser deposits in Europe and Asia.
Tar sands are frequently defined as sand saturated with a highly viscous crude petroleum material not recoverable in its natural state through a well by ordinary production methods. The hydrocarbon contained in tar sand deposits are generally highly bituminous in character. The tar sand deposits are generally arranged as follows. Fine quartz sand is coated with a layer of water and the bituminous material occupies most of the void space around the wetted sand grains. The balance of the void volume may be filled with connate water, and occasionally a small volume of gas which is usually air or methane. The sand grains are packed to a void volume of about 35%, which corresponds to about 83% by weight sand. The balance of the material is bitumen and water. The sum of bitumen and water will almost always equal about 17% by weight, with the bitumen portion varying from around 2% to around 16%.
It is an unusual characteristic of tar sand deposits that the sand grains are not in any sense consolidated, that is to say the sand is essentially suspended in the solid or nearly solid hydrocarbon material. The API gravity of the bitumen usually ranges from about 6 to about 8, and the specific gravity at 60F. is from about 1.006 to about 1.027. Approximately 50% of the bitumen is distillable without cracking, and the sulfur content averages between 4 and 5% by weight. The bitumen is also very viscous, and so even if it is recoverable by an in situ separation technique, some on-site refining of the produced petroleum must be undertaken in order to convert it to a pumpable fluid.
Bitumen may be recovered from tar sand deposits by mining or by in situ processes. Most of the recovery to date has been by means of mining, although this is limited to instances where the ratio of the overburden thickness to tar sand deposit thickness is economically suitable, generally defined as one or less. In situ processes have been proposed which may be categorized as thermal, such as fire flooding or steam injection, and steam plus emulsification drive processes. Generation of thermal heat necessary to mobilize the bitumen by means of a subterranean atomic explosion has been seriously considered, although has not yet been attempted.
Despite the many proposed methods for recovering bitumen from tar sand deposits, there has still been no successful exploitation of such deposits by in situ pro cessing on a commercial scale up to the present time. Accordingly, in view of the lack of commercial success of any of the methods proposed to date, and especially in view of the enormous reserves present in this form which are needed to help satisfy present energy needs, there is a substantial need for a satisfactory method for recovery of bitumen from tar sand deposits.
BRIEF DESCRIPTION OF THE DRAWING i The attached drawing illustrates in cross sectional view a tar sand deposit being subjected to in situ recovery of bitumen therefrom by the method of our invention.
SUMMARY OF THE INVENTION We have discovered, and this constitutes our invention, that viscous petroleum may be recovered from subterranean, viscous petroleum containing formations by a method employing a volatile: solvent such as carbon disulfide or toluene under conditions which will maintain the solvent within the oil recovery reservoir during most of the recovery time, so that it will reflux up into the reservoir and solubilize viscous petroleum, losing heat and condensing, and thereafter moving down into a flow path containing a heated fluid moving horizontally through the formation. The process requires that a communication path for fluid flow be es tablished deep in the formation by means such as by hydraulic fracturing and propping with a coarse permeable material, after which a heated fluid is injected into the communication path to heat the path at least a substantial distance away from the injection well to a temperature in excess of the boiling point of the volatile solvent to be used, followed by injection of the solvent into the reservoir via the heated communication path. The solvent will be vaporized and will move up into the formation, dissolving petroleum and losing heat as it goes. The liquified solvent with petroleum or bitumen dissolved therein will then flow down into the lower part of the formation to the previously established, heated communication path, where it will contact the heated fluid being injected through the formation via this path. The bitumen will be transferred to this moving heated fluid, and the volatile solvent will be revaporized and move back up into the formation to solubilize additional petroleum. The injected heated fluid may be aqueous such as hot water or steam or may be a nonaqueous, low volatility solvent such as aromatic hydrocarbons such as toluene and xylene and aliphatic hydrocarbons having from three to seven carbon atoms. Steam traps may be installed on the production well near the perforations establishing fluid flow communication with the flow path of the formations so as to insure that no vaporized solvent or other gaseous material leaves. the formation.
DESCRIPTION OF THE PREFERRED EMBODIMENTS l. The Process v The process of our invention may best be understood by reference to the figure, illustrating how a subterranean formation may be exploited according to our invention. For example, a tar sand deposit 1 is located too deep for strip mining and the petroleum contained therein is highly bituminous in character and much too viscous to permit recovery thereof through wells drilled into the formation by normal means. An injection well 2 is drilled to the formation and fluid communication between the well and the formation is established deep into the formation by means of perforations 3. A production well 4 is also drilled into the formation, and fluid flow communication means are similarly established deep in the formation by means of perforations 5.
The first step of our process requires that a communication path 6 be established as low as possible in the formation. The ideal communication path is an essentially horizontal, pancake shaped zone of high permeability at the very bottom of the tar sand or petroleum reservoir. This is not always possible to achieve, however, and this idealized communication zone is not absolutely essential for the successful implementation of our process.
It is sometimes discovered that there is a water saturated zone in the very bottom of the petroleum reservoir, and this may be utilized successfully to establish the fluid communication path in accordance with our process. The water saturated zone may be opened up by injecting into the zone a heated fluid such as steam, which will channel preferentially through this water saturated zone to the production well 4. Any asphaltic or other hydrocarbon materials present in the water saturated zone will be dissolved, and the permeability will be opened up considerably thereby.
Generally, it will be necessary to convert a substantially hydrocarbon saturated zone in the base of the reservoir to a high permeability, communication path by some other means such as hydraulic fracturing. Hydraulic fracturing is a well known technique for establishing a communication path between an injection well and a production well, and by injecting the fracturing fluid low in the reservoir it is possible to position the fracture essentially at the bottom of the oil filled zone. It is not essential that the fracture planes be horizontally oriented, although it is of course preferable that they be. This cannot be counted on, however, since there is evidence that hydraulic fractures at the deeper horizons are predominantly vertical rather than horizontal.
In any event, a communication path of some sort will be created, generally confined to the lower portion of the petroleum reservoir. After the fracture has been established, and without diminishing the fracture pressure, a propping agent must be injected into the fracture in order to prevent healing of the fracture which woulddestroy its usefulness for fluid flow communication purposes. Gravel and sand or mixtures thereof are successfully employed for propping agents, and it is desirable in the instance of tar sand deposits that a wide variation of particle sizes be employed to avoid flowing of the tar sand materials back into the propped fracture zone.
The next step in the employment of our process requires that this previously created communication zone be heated to a fairly high temperature a substantial distance away from the injection well, ideally extending throughout the formation to the production well. Ordinarily it will be satisfactory to monitor the temperature of the fluids being produced at the production well as a method of determining when the heating has extended the desired distance through the previously created communication path. The minimum temperature to which the path must be heated will be determined by the particular volatile solvent chosen for use, which will be described in greater detail hereinafter. Ordinarily it will be possible to achieve the desired heating effect by continually injecting the heated fluid into the injection well and producing the injected fluid at the production well, noting the temperature of the produced fluid and continuing this operation until the produced fluid itself indicates the communication path has been heated in its entirety from the injection well to the production well. Sometimes it is necessary to reverse the flow, with the injected fluid being injected into the well which was originally the production well, and recovering the fluid from the original injection well, as a means of insuring that the communication path in the vicinity of the injection well is heated to the preselected temperature.
The heating fluid itself will be discussed in greater detail hereinafter, although it is sufficient here to say that a wide variety of fluids may be advantageously employed for this purpose. Steam or hot water may be utilized, or a nonaqueous fluid having a volatility substantially less than the volatile solvent to be utilized may also serve as the heating fluid.
After the communication path has been heated to the desired level, a quantity of the volatile solvent is injected into the communication path. The same injection well and equipment will be utilized for this purpose, and it should be understood that our process does not contemplate the continuous injection of the volatile solvent into one well and production thereof from the production well. A quantity of solvent, usually from about 0.01 to 0.20 pore volumes being adequate, will be injected and will remain in the formation throughout the continuation of our recovery operation, Since the solvent is highly volatile, it will be vaporized immediately upon entering the preheated communication path, and then in the gaseous form it will move upward into the petroleum saturated zone. AS the solvent moves up into the zone, it is absorbed into the petroleum or bitumen contained therein, and also loses heat as it moves up into the cooler portions of the formation. Since the heating operation is confined to the previously established communication zone, there will be substantial temperature gradient between the bottom and top of the formation. The solvent will eventually condense to its liquid form, and then will begin moving back down toward the zone because of its higher density. The liquid solvent will carry bitumen dissolved therein with it, and by this method the bitumen is carried down into the heated communication path.
Once the mixture of liquid solvent and bitumen moves down to the heated communication path, the bitumen is transferred from the solvent to the heating fluid which is being continually passed through this communication path. The volatile solvent is immediately revaporized, and begins to move back up into the petroleum saturated formation. The result is the creation of a solvent action zone the upper limits of which are defined by line 7 in the figure, and the bottom of which is defined by the heated communication path. The solvent action zone defined by line 7 will initially be quite small, but will continually grow until it has ultimately encompassed the entire formation above the communication zone and between the injection and production well. The volatile solvent will never leave the formation during the course of the production operation, since the fluid communication zone 6 is heated to a temperature in excess of the boiling point of the solvent all the way to the perforations 5 and production well 4. Thus, even in the area immediately adjacent to the production well, the solvent can exist only in a vapor phase. Since the production well 4 is provided with steam traps, no vapor is permitted to flow to the surface through well 4, so the solvent will necessarily remain in the formation. This is an especially attractive feature where an expensive solvent or a solvent having serious flammability or other hazardous characteristics is utilized.
After all of the volatile solvent has been injected, the heated fluid is continually injected into the injection well 2 and continuous to pass through the communication zone 6 to production well 4 to where it is produced to the surface. Separation of produced petroleum from the heating fluid is accomplished on the surface, and it will generally be preferable to recycle the heating fluid through the formation in order to reduce the total volume of fluid needed. This is still true in the instance of utilizing steam or hot water as the heating fluid, since the quantity of fluid to be disposed of will be reduced substantially by the recycling process.
After the formation has been essentially depleted of petroleum or bitumen, it will generally be desirable to recover the volatile solvent for reuse. This may be accomplished by injecting water into the production well to displace the solvent toward the production well. It is desirable in this phase to utilize cold water, in order to cool the communication path and cause condensation of the volatile solvent to facilitate its recovery. The produced fluid in this final phase will comprise water or other inexpensive displacing fluid and the volatile solvent, which can be separated on the surface for reuse of the solvent in another area.
In full scale operations, the heating phase need not be a separate step preceding the volatile solvent injection phase. It will be satisfactory to inject solvent and heat ing fluid simultaneously into the communication path, and inject only heating fluid after the desired quantity of solvent has been injected.
II. The Heating Fluid The heating fluid which is injected into the communication path during the second and third parts of the process may be either aqueous or nonaqueous, and its choice will depend in part on the particular characteristics of the formation in which the process is to be applied, and to someextent may be influenced by the volatile solvent to be utilized. Ordinarily, hot water or steam will be the preferable heating fluid, because of their low cost and wide spread availability. Although steam is a very satisfactory fluid for use in certain instances, there are circumstances which sometimes make hot water the preferable heating fluid. For example, when it is desired to use carbon disulfide as the volatile solvent, there is a possibility of a vapor pahse reaction between carbon disulfide and water vapor at higher temperatures, especially from 200C. up depending on the nature of the mineral constituents of the formation which may serve as a catalyst for the reaction. The particular reaction which carbon disulfide undergoes in the presence of water vapor at high temperatures, and especially in the presence of a catalyst, de-
pends in part on the nature of the catalyst present and on the temperature to which the materials are subjected. In the range of from about 200 to about 500C, carbon disulfide and water react to form hydrogen sulfide and carbon dioxide, and the reaction tends to be fairly quantitative in the higher portions of the specified range. Below about 200C. there is a reaction between carbon disulfide and water vapor to form carbonyl sulfide, COS. Accordingly, it is preferable to keep the steam temperature below about 200C., and the best results are obtained in the use of hot water rather than steam vapor. The formation of carbonyl sulfide is not harmful to the reaction nor dangerous to personnel present in the vicinity of the production operations, since carbonyl sulfide boils at approximately minus C. compared to the plus 46C. boiling point for carbon disulfide. Accordingly, any carbonyl sulfide produced will certainly remain in the formation rather than being produced to the surface of the earth. Nevertheless, carbon disulfide is consumed by the reaction and since the reaction is irreversible, a loss of solvent .will result from the reaction. For this reason the reaction should be avoided. One method of avoiding the reaction, for example, is to operate under conditions of temperature and pressure of the injected heating fluid so as to insure that it remains in the liquid phase, since the reaction only occurs in vapor phase situations. Ac cordingly, one preferred embodiment employs carbon disulfide as the volatile solvent and hot water as the heating fluid. In very viscous materials, it may be desirable to incorporate in the injected hot water a small amount of caustic in order to form an emulsion in the bottom zone with very viscous petroleum which would not otherwise be recoverable by the thermal effects of hot water alone. Surfactant materials such as polyphosphates or petroleum sulfonates may also be included in the hot water.
Another means for using carbon disulfide so as to avoid the formation of the above described reaction is to utilize a nonaqueous fluid, preferably a fluid which is an effective solvent for petroleum or bitumen and which as a boiling point substantially higher than carbon disulfide. For example, toluene has a boiling point of ll0.8C. and benzene has a boiling point of C. Either material or a mixture thereof would be a satisfactory heating fluid, and it would be possible to maintain the temperature of the injected fluid at a few degrees below its boiling point to insure that the injected fluid will remain in the liquid state, and that it will heat the formation to a temperature sufficiently higher than the volatile solvent so that the solvating, refluxing action described in the process section of this specification will take place. Accordingly, another preferred embodiment of our invention utilizes an aromatic solvent such as benzene, toluene or a mixture thereof as the heating fluid, which can be utilized to heat the previously created communication path to a temperature close to its boiling point. After the heating phase is completed, carbon disulfide is utilized as the volatile solvent, and it will vaporize, dissolve tar, condense and move back down into the communication path where the tar can be transported to the production well by the injected heating fluid. This is an especially attractive feature for a very viscous petroleum such as bitumen obtained in tar sand, since the heated aromatic fluid is an excellent solvent for bitumen.
Aliphatic hydrocarbons may also be utilized as the heating fluid, so long as their boiling point is sufficiently higher than the volatile solvent utilized to insure that the volatile solvent will remain vaporized even in the vicinity of the production well. In the instance of using carbon disulflde as the volatile solvent, aliphatic hydrocarbons having seven or more carbon atoms will be satisfactory. For example, the boiling points of the various heptane isomers varies from 79 to 98C., which is sufficiently higher than the boiling point of carbon disulflde, (46.3C.) to permit the use of liquid heptane or higher molecular weight aliphatic hydrocarbons heated to a temperature slightly below their boiling point as the heating fluid, which will maintain the communication path temperature above the boiling point of carbon disulflde.
Mixtures of aliphatic and aromatic hydrocarbons may also be utilized as the heating fluid, so long as the boiling point of the mixture is substantially higher than the boiling point of the volatile solvent employed in our process. III. The Volatile Solvent As described previously, carbon disulflde is an especially preferred choice for the volatile solvent for use in the process of our invention. Carbon disulflde has a boiling point of 463C, and is an excellent solvent for the asphaltic materials present in many viscous crudes, especially bituminous materials such as tar sands. In order to achieve the optimum performance of our invention, it is desirable that the volatile solvent have a volatility such that it will be vaporized in the heated communication zone, but will condense in the upper portion of the reservoir at ambient formation temperatures. For example, if one attempted to utilize methane as the volatile solvent in our process, it would vaporize but would not condense in the upper portion of the reservoir, and so would not dissolve bitumen and transport it down into the communication path. Accordingly, the ideal solvent for use in our process has a boiling point substantially below the temperature of the heated communication path, but which is higher than the natural temperature of the formation.
Aromatic solvents such as toluene and benzene may also be utilized as the volatile solvent, although obviously they cannot serve both as the volatile solvent and as the heating fluid described in Section II. If it is desired to utilize benzene, for example, as the volatile solvent, benzene having a boiling point of 801C, it will be necessary to use this in combination with a heating fluid which has a boiling point at least 10 to higher. For example, hot water or steam may be utilized as the heating fluid. Accordingly, another preferred embodi-. ment of our invention utilizes steam or hot water as the heating fluid and benzene as the volatile solvent.
Certain aliphatic hydrocarbons may also be utilized,
although it is necessary to chose them carefully so as to have a material which can be vaporized in the communication path and which will condense to a liquid in the upper portions of the formation when the solvent has cooled to the natural temperature of the formation, so that it will dissolve petroleum contained therein and then flow down into the heated communication path. For example, aliphatic hydrocarbons having from about 4 to about 9 carbon atoms may be utilized, so long as they are paired with appropriate heating fluids having a boiling point at least 15C. higher than the volatile solvent utilized. Accordingly, another preferred embodiment of our invention utilizes steam or hot water as the heating fluid and aliphatic hydrocarbons having from 4 to 6 carbon atoms as the volatile solvent. Somewhat higher molecular weight aliphatic hydrocarbons may be utilized as the volatile solvent if steam is used as the heating fluid, which temperature is made at least 10C. higher than the boiling point of the volatile solvent utilized.
It should be understood that certain aromatic and aliphatic hydrocarbon species have been included in the section dealing with both heating fluid and volatile solvent. In no instance can the same species be used as the heating fluid and the volatile solvent in the same application. The heating fluid and volatile solvent are interrelated and the paramount consideration must be that the volatile solvent boiling point be substantially less than the temperature of the heating fluid. If it is desired to insure that the heating fluid be maintained in a liquid phase, then the boiling point of the heating fluid must be at least 10 or 15C. greater than the boiling point of the volatile solvent.
IV. Field Example Our invention is best understood by a reference to the following field example, which is offered only as an illustrative embodiment of our invention, and is not intended to be limitative or restricted thereof.
A tar sand deposit is located at a depth of 200 feet and it is determined that the thickness of the formation is 65 feet. It is also determined that the petroleum is in the form of a highly bituminous hydrocarbon, and its viscosity at the formation temperature is much too high to permit recovery thereof by conventional means. An injection well is drilled to the bottom of the formation, and perforations are formed essentially at the bottom of the petroleum saturated zone. A production well is drilled approximately feet distance from the injection well, and perforations are similarly made slightly above the bottom of the petroleum saturated zone. The production well is also equipped with a steam trap so that only liquids can be produced from the formation, and vapors are excluded therefrom.
A fluid communication path low in the formation is formulated by fracturing the formation using conventional hydraulic fracturing techniques, and injecting a gravel sand mixture into the fracture to hold it open and prevent healing of the fracture. Next, hot water is injected into the formation at a temperature of 200F., and injection is continued until the temperature of water produced at the production well rises to a temperature of F., indicating that the communication path has been heated uniformly from the injection well to the production well.
It is determined that the area swept by the two well pilot field program is 750 square feet and so the total volume involved in the pilot will be 750 X 60 or 45,000 cubic feet. The porosity of this particular interval is only 20% so the total pore volume will be 9,000 cubic feet. A 0.10 pore volume (900 cubic feet or 6700 gallons) slug of the volatile solvent, carbon disulflde in this particular instance, is injected into the injection well. After the carbon disulflde has been injected into the formation, injection of hot water is continued into the formation and production taken from the production well. Carbon disulflde vaporizes within the formation, moves up into the formation and loses sufficient heat to condense, thereafter dissolving bitumen, and the mixture of carbon disulflde and bitumen moves down into the formation until it encounters the heated communication path. Upon contacting the heated communication path through which hot water is continually being passed, the carbon disulfide is revaporized but the bitumen remains in the communication path. The heating fluid raises the temperature of the bitumen, and
the material is then transported to the production well where it is passed to the surface.
This production sequence is continued, with hot water being injected into the injection well and a mixture of hot water and bitumen being taken from the production well, without any additional carbon disulfide or other solvent being injected into the formation. Bitumen is separated on the surface from the produced fluid, and is then subjected to sufficient processing in the vicinity of the production well to permit it to be transported via a pipeline to a remotely located refinery. The water is reheated as necessary and reinjected into the formation, in order to minimize the amount of water necessary for the operation, and also to eliminate the need for extraneous injection wells for water dis posal. After the concentration of bitumen in the produced hot water begins to decline, it is determined that essentially all of the formation has been contacted by the volatile solvent and all of the bitumen present therein has been recovered. Thereafter, cold water is injected into the injection well to reduce the temperature of the communication path, which condenses car-, bon disulfide therefrom and the material is produced along with the produced cold water. Carbon disulfide is easily separated from water on the surface by vac uum distillation, so the material may be utilized in another location. V. Experimental Evaluation In order to establish the operability of our invention, and further to determine the effectiveness and optimum concentrations of materials for use therein, the following experimental work was performed.
A cell suitable for oil recovery studies under controlled laboratory conditions was packed first with a clean sand layer approximately one-eighth inch thick at the center of the cell, extending from the injection point to the production point, and the remainder of the cell was packed with tar sand to a density approximating the density encountered in actual formations. The clean sand layer at the base of the tar sand represented the communication path between the injection means and the production means which will be artificially produced in field application by fracturing or other means, if a communication path does not already exist. A quantity of carbon disulfide was injected into the cell followed by injection of saturated steam at 300 psia and 417F. In this particular test, the gaseous and liquid effluent were both removed and separated so as to study the compositions thereof, and it was determined that the gaseous effluent consisted of one-third carbon disulfide, one-third carbonyl sulfide, and one-third hydrogen sulfide, indicating that the reactions described previously had occurred to some extent. Nevertheless, bitumen was recovered from the cell. Approximately 78% of the bitumen was recovered, which is an unusually high recovery efficiency for tar sands.
While our invention has been described in terms of a number of specific illustrative embodiments, it should be understood that it is not so limited. Numerous variations will be apparent to persons skilled in the art without departing from the true spirit and scope of our invention, and it is intended that our invention be limited only by such restrictions or limitations as are imposed in the appended claims.
1. A method for recovering petroleum from subterranean, viscous petroleum containing formations including tar sand deposits, said formations being penetrated by at least one injection well and by at least one production well, comprising:
a. establishing a fluid communication path low in the formations between the injection well and the production well;
b. injecting a heating fluid into the communication path;
0. continuing injection of said heating fluid and recovering the fluid from the production well until the temperature of the formation has increased for a substantial distance from the injection well to a temperature substantially above the natural temperature of the formation;
d. injecting into the heated communication path a volatile solvent for the petroleum contained in the formations, said solvent having a boiling point greater than the natural formation temperature and substantially lower than the temperature to which the communication path has been heated; and
e. continuing injecting the heating fluid into the injection well and producing same at the production well, with the formation petroleum mixed there with.
2. A method as recited in claim 1 wherein the communication path iscreated by hydraulic fracturing.
3. A method as recited in claim 1 wherein the formation contains a substantially water saturated, porous zone in the lower part thereof, and the communication path low in the formation is created by injecting a heated, aqueous fluid selected from the group consisting of steam'and hot water.
4. A method as recited in claim ll wherein the heating fluid comprises an aqueous fluid selected from the group consisting of steam and hot water.
5. A method as recited in claim 4 wherein the heating fluid is steam.
6. A method as recited in claim 4 wherein the heating fluid is hot water.
7. A method as recited in claim 4 wherein sodium hydroxide is included with the aqueous heating fluid.
8. A method as recited in claim; 4 wherein a surfactant is included with the aqueous heating fluid.
9. A method as recited in claim I wherein the heating fluid is an aromatic hydrocarbon.
10. A method as recited in claim 9 wherein the aromatic hydrocarbon heating fluid is benzene.
11. A method as recited in claim 9 wherein the aromatic hydrocarbon heating fluid is toluene.
12. A method as recited in claim 1 wherein the heating fluid is an aliphatic hydrocarbon having from 3 to 9 carbon atoms.
13. A method as recited in claim 1 wherein the volatile solvent is carbon disulfide.
14. A method as recited in claim 13 wherein the heating fluid used in conjunction with carbon disulfide is a liquid and the temperature of the heating fluid is below 210F.
15. A method as recited in claim 1 wherein the volatile solvent is an aromatic hydrocarbon solvent.
16. A method as recited in claim wherein the aromatic, volatile solvent is benzene.
17. A method as recited in claim 15 wherein the aromatic solvent is toluene.
18. A method as recited in claim 1 wherein the volatile solvent is an aliphatic hydrocarbon having from 3 to 9 carbon atoms.
19. A method for recovering bitumen from a tar sand deposit comprising:
a. forming a permeable flow path near the bottom of the tar containing portion of the formation;
b. injecting hot water whose temperature is below 210F. and above the boiling point of carbon disulfide into the permeableflow path;
c. injecting a predetermined quantity of carbon disulfide into the heated permeable flow path;
(1. continuing injecting the hot water into the formation, and
e. recovering the hot water with formation tar mixed therewith from the formation.
20. A method as recited in claim 19 wherein from about 0.05 to about 0.1 pore volumes of carbon disulfide is injected into the formation.
21. A method for recovering bitumen from tar sand deposits comprising:
a. forming a permeable zone near the bottom of the tar sand deposit;
b. injecting a nonaqueous fluid having a boiling point of at least 60C. into the permeable zone, said fluid being heated to a temperature greater than the boiling point of carbon disulfide;
c. injecting from about 0.01 to about 0.10 pore volumes of carbon disulflde into the heated permeable zone;
d. continuing injecting the heated nonaqueous fluid and producing said fluid with bitumen dissolved therein from the tar sand deposit. 22. A method as recited in claim 21 wherein the heated nonaqueous fluid is an aromatic hydrocarbon.
23. A method as recited in claim 22 wherein the aromatic hydrocarbon is benzene.
24. A method as recited in claim 22 wherein the aromatic hydrocarbon is toluene.
25. A method as recited in claim 21 wherein the nonaqueous fluid is an aliphatic hydrocarbon having from 7 to 12 carbon atoms.
26. A method for recovering viscous petroleum including bitumen from a viscous petroleum containing formation including a tar sand deposit comprising:
a. forming a permeable flow path near the bottom of the petroleum containing formation;
b. introducing an aqueous fluid heated to a temperature of at least centrigrade into the permeable flow path;
c. introducing an aromatic or aliphatic hydrocarbon solvent for the formation petroleum having a boiling point at least 10C. below the temperature of the heated aqueous fluid of (b) and above the natural formation temperature into the permeable flow path, and
d. continuing injection of the heated aqueous fluid into the formation while producing the aqueous fluid with viscous formation petroleum mixed therewith from the formation.
27. A method as recited in claim 26 wherein the hydrocarbon solvent is benzene.
28. A method as recited in claim 26 wherein the heated aqueous fluid is steam heated to a temperature above C. and the hydrocarbon solvent is-toluene.
|Cited Patent||Filing date||Publication date||Applicant||Title|
|US2708481 *||Jul 26, 1951||May 17, 1955||Texas Co||Recovery of hydrocarbons from subsurface reservoirs|
|US2910123 *||Aug 20, 1956||Oct 27, 1959||Pan American Petroleum Corp||Method of recovering petroleum|
|US2974937 *||Nov 3, 1958||Mar 14, 1961||Jersey Prod Res Co||Petroleum recovery from carbonaceous formations|
|US3003554 *||Dec 5, 1957||Oct 10, 1961||Pan American Petroleum Corp||Secondary recovery process with controlled density fluid drive|
|US3221813 *||Aug 12, 1963||Dec 7, 1965||Shell Oil Co||Recovery of viscous petroleum materials|
|US3396791 *||Sep 9, 1966||Aug 13, 1968||Shell Oil Co||Steam drive for incompetent tar sands|
|US3500916 *||Oct 3, 1968||Mar 17, 1970||Shell Oil Co||Method of recovering crude oil from a subsurface formation|
|US3500917 *||Aug 28, 1968||Mar 17, 1970||Shell Oil Co||Method of recovering crude oil from a subsurface formation|
|US3513914 *||Sep 30, 1968||May 26, 1970||Shell Oil Co||Method for producing shale oil from an oil shale formation|
|US3729053 *||Jan 5, 1972||Apr 24, 1973||Amoco Prod Co||Method for increasing permeability of oil-bearing formations|
|Citing Patent||Filing date||Publication date||Applicant||Title|
|US3938590 *||Jun 26, 1974||Feb 17, 1976||Texaco Exploration Canada Ltd.||Method for recovering viscous asphaltic or bituminous petroleum|
|US3945435 *||Nov 7, 1974||Mar 23, 1976||The Ralph M. Parsons Co.||In situ recovery of hydrocarbons from tar sands|
|US3946810 *||Nov 7, 1974||Mar 30, 1976||The Ralph M. Parsons Company||In situ recovery of hydrocarbons from tar sands|
|US3983939 *||Oct 31, 1975||Oct 5, 1976||Texaco Inc.||Method for recovering viscous petroleum|
|US4022277 *||May 19, 1975||May 10, 1977||The Dow Chemical Company||In situ solvent fractionation of bitumens contained in tar sands|
|US4067391 *||Jun 18, 1976||Jan 10, 1978||Dewell Robert R||In-situ extraction of asphaltic sands by counter-current hydrocarbon vapors|
|US4068716 *||Sep 17, 1976||Jan 17, 1978||Texaco Inc.||Oil recovery process utilizing aromatic solvent and steam|
|US4071458 *||Sep 17, 1976||Jan 31, 1978||Texaco Inc.||Oil displacement fluid containing a solubilizing agent|
|US4085803 *||Mar 14, 1977||Apr 25, 1978||Exxon Production Research Company||Method for oil recovery using a horizontal well with indirect heating|
|US4158638 *||Mar 27, 1978||Jun 19, 1979||Gulf Research & Development Company||Recovery of oil from oil shale|
|US4293035 *||Jun 7, 1979||Oct 6, 1981||Mobil Oil Corporation||Solvent convection technique for recovering viscous petroleum|
|US4327805 *||Sep 18, 1979||May 4, 1982||Carmel Energy, Inc.||Method for producing viscous hydrocarbons|
|US4373585 *||Jul 21, 1981||Feb 15, 1983||Mobil Oil Corporation||Method of solvent flooding to recover viscous oils|
|US4373586 *||Aug 7, 1981||Feb 15, 1983||Mobil Oil Corporation||Method of solvent flooding to recover viscous oils|
|US4458758 *||Mar 8, 1982||Jul 10, 1984||Mobil Oil Corporation||Selected well completion for improving vertical conformance of steam drive process|
|US4469177 *||Nov 29, 1982||Sep 4, 1984||Mobil Oil Corporation||Recovery of viscous oil from asphaltic oil-containing formations|
|US4501326 *||Jan 17, 1983||Feb 26, 1985||Gulf Canada Limited||In-situ recovery of viscous hydrocarbonaceous crude oil|
|US4697642 *||Jun 27, 1986||Oct 6, 1987||Tenneco Oil Company||Gravity stabilized thermal miscible displacement process|
|US4756369 *||Nov 26, 1986||Jul 12, 1988||Mobil Oil Corporation||Method of viscous oil recovery|
|US5167280 *||Jun 24, 1991||Dec 1, 1992||Mobil Oil Corporation||Single horizontal well process for solvent/solute stimulation|
|US7426959 *||Apr 19, 2006||Sep 23, 2008||Shell Oil Company||Systems and methods for producing oil and/or gas|
|US7601320||Apr 19, 2006||Oct 13, 2009||Shell Oil Company||System and methods for producing oil and/or gas|
|US7640987||Jan 5, 2010||Halliburton Energy Services, Inc.||Communicating fluids with a heated-fluid generation system|
|US7644769||Jan 12, 2010||Osum Oil Sands Corp.||Method of collecting hydrocarbons using a barrier tunnel|
|US7654322 *||Aug 11, 2008||Feb 2, 2010||Shell Oil Company||Systems and methods for producing oil and/or gas|
|US7677673||Mar 5, 2007||Mar 16, 2010||Hw Advanced Technologies, Inc.||Stimulation and recovery of heavy hydrocarbon fluids|
|US7770643||Aug 10, 2010||Halliburton Energy Services, Inc.||Hydrocarbon recovery using fluids|
|US7809538||Jan 13, 2006||Oct 5, 2010||Halliburton Energy Services, Inc.||Real time monitoring and control of thermal recovery operations for heavy oil reservoirs|
|US7832482||Oct 10, 2006||Nov 16, 2010||Halliburton Energy Services, Inc.||Producing resources using steam injection|
|US7926561 *||Oct 30, 2008||Apr 19, 2011||Shell Oil Company||Systems and methods for producing oil and/or gas|
|US8127865||Apr 19, 2007||Mar 6, 2012||Osum Oil Sands Corp.||Method of drilling from a shaft for underground recovery of hydrocarbons|
|US8136592 *||Aug 8, 2007||Mar 20, 2012||Shell Oil Company||Methods for producing oil and/or gas|
|US8167960||Oct 21, 2008||May 1, 2012||Osum Oil Sands Corp.||Method of removing carbon dioxide emissions from in-situ recovery of bitumen and heavy oil|
|US8176982||May 15, 2012||Osum Oil Sands Corp.||Method of controlling a recovery and upgrading operation in a reservoir|
|US8209192||Jun 26, 2012||Osum Oil Sands Corp.||Method of managing carbon reduction for hydrocarbon producers|
|US8287050||Jul 17, 2006||Oct 16, 2012||Osum Oil Sands Corp.||Method of increasing reservoir permeability|
|US8313152||Nov 21, 2007||Nov 20, 2012||Osum Oil Sands Corp.||Recovery of bitumen by hydraulic excavation|
|US8511384||Jul 18, 2008||Aug 20, 2013||Shell Oil Company||Methods for producing oil and/or gas|
|US8596371||Mar 15, 2012||Dec 3, 2013||Shell Oil Company||Methods for producing oil and/or gas|
|US8656997 *||Apr 14, 2009||Feb 25, 2014||Shell Oil Company||Systems and methods for producing oil and/or gas|
|US8857512 *||May 29, 2008||Oct 14, 2014||N-Solv Corporation||Situ extraction process for the recovery of hydrocarbons|
|US8869891||Nov 18, 2008||Oct 28, 2014||Shell Oil Company||Systems and methods for producing oil and/or gas|
|US8960564 *||Oct 30, 2013||Feb 24, 2015||Ronald L. Chandler||Method for hydraulically fracturing a well using an oil-fired frac water heater|
|US9057257||Nov 18, 2008||Jun 16, 2015||Shell Oil Company||Producing oil and/or gas with emulsion comprising miscible solvent|
|US9085972 *||Aug 6, 2012||Jul 21, 2015||Gilman A. Hill||Integrated in situ retorting and refining of heavy-oil and tar sand deposits|
|US9321967||Aug 17, 2010||Apr 26, 2016||Brack Capital Energy Technologies Limited||Oil sands extraction|
|US20060254769 *||Apr 19, 2006||Nov 16, 2006||Wang Dean C||Systems and methods for producing oil and/or gas|
|US20080073079 *||Mar 5, 2007||Mar 27, 2008||Hw Advanced Technologies, Inc.||Stimulation and recovery of heavy hydrocarbon fluids|
|US20080087425 *||Aug 8, 2007||Apr 17, 2008||Chia-Fu Hsu||Methods for producing oil and/or gas|
|US20080302532 *||Aug 11, 2008||Dec 11, 2008||Wang Dean Chien||Systems and methods for producing oil and/or gas|
|US20090025935 *||Apr 19, 2006||Jan 29, 2009||Johan Jacobus Van Dorp||System and methods for producing oil and/or gas|
|US20090056941 *||Jul 18, 2008||Mar 5, 2009||Raul Valdez||Methods for producing oil and/or gas|
|US20090188669 *||Jul 30, 2009||Steffen Berg||Systems and methods for producing oil and/or gas|
|US20100163227 *||Mar 11, 2010||Jul 1, 2010||Hw Advanced Technologies, Inc.||Stimulation and recovery of heavy hydrocarbon fluids|
|US20100236783 *||May 29, 2008||Sep 23, 2010||N-Solv Corporation||situ extraction process for the recovery of hydrocarbons|
|US20100307759 *||Nov 18, 2008||Dec 9, 2010||Steffen Berg||Systems and methods for producing oil and/or gas|
|US20110094750 *||Apr 14, 2009||Apr 28, 2011||Claudia Van Den Berg||Systems and methods for producing oil and/or gas|
|US20110108269 *||Nov 18, 2008||May 12, 2011||Claudia Van Den Berg||Systems and methods for producing oil and/or gas|
|US20110132602 *||Apr 14, 2009||Jun 9, 2011||Claudia Van Den Berg||Systems and methods for producing oil and/or gas|
|US20110180254 *||Jul 14, 2009||Jul 28, 2011||Claudia Van Den Berg||Systems and methods for producing oil and/or gas|
|US20130240210 *||Sep 29, 2011||Sep 19, 2013||David P. Yale||Systems and Methods For Injecting A Particulate Mixture|
|US20140048268 *||Oct 30, 2013||Feb 20, 2014||Ronald L. Chandler||Method for Hydraulically Fracturing a Well Using An Oil-Fired Frac Water Heater|
|EP2867455A4 *||Jun 25, 2013||Apr 6, 2016||Shell Int Research||Petroleum recovery process and system|
|EP2867456A4 *||Jun 25, 2013||Dec 30, 2015||Shell Int Research||Petroleum recovery process and system|
|WO2009067418A1 *||Nov 18, 2008||May 28, 2009||Shell Oil Company||Systems and methods for producing oil and/or gas|
|WO2009067420A1 *||Nov 18, 2008||May 28, 2009||Shell Oil Company||Systems and methods for producing oil and/or gas|
|WO2014004490A1 *||Jun 25, 2013||Jan 3, 2014||Shell Oil Company||Petroleum recovery process and system|
|WO2014204849A1 *||Jun 16, 2014||Dec 24, 2014||Shell Oil Company||Oil recovery system and method|
|U.S. Classification||166/271, 166/272.1|
|International Classification||E21B43/24, E21B43/16|