Method and a system of recovering and processing a hydrocarbon mixture from a subterranean formation

Abstract

The present invention relates to a method and system for recovering and processing a hydrocarbon mixture from a subterranean formation. The method comprises: (i) mobilizing said hydrocarbon mixture; (ii) recovering said mobilized hydrocarbon mixture; (iii) coking said recovered hydrocarbon mixture to produce decoked hydrocarbon and coke; (iv) combusting said coke to generate steam and/or energy and CO.sub.2; (v) upgrading said decoked hydrocarbon by hydrogen addition to produce upgraded hydrocarbon; and (v) adding a diluent to the decoked hydrocarbon prior to upgrading and/or adding a diluent to the upgraded hydrocarbon; wherein said method is at least partially self-sufficient in terms of steam and/or energy and diluent.

Claims

1. A method of recovering and processing a hydrocarbon mixture from a subterranean formation, comprising: (i) mobilising said hydrocarbon mixture; (ii) recovering said mobilised hydrocarbon mixture; (iii) fractionating said recovered hydrocarbon mixture to produce a heavier fraction and at least one lighter fraction comprising naphtha, kerosene and/or light gas oils; (iv) coking said heavier fraction to produce decoked hydrocarbon and coke; (v) combusting said coke to generate steam and/or energy and CO.sub.2; (vi) adding a diluent from a diluent addition tank to the decoked hydrocarbon prior to upgrading in an upgrader, wherein said diluent addition tank is directly connected to said upgrader; and (vii) upgrading said decoked hydrocarbon by hydrogen addition to produce upgraded hydrocarbon; wherein said method is at least partially self-sufficient in terms of steam and/or energy and wherein at least some of said diluent comprises said lighter fraction comprising naphtha, kerosene and/or light gas oils obtained directly during fractionating of said recovered hydrocarbon mixture.

2. A method as claimed in claim 1, wherein said method is at least partially self-sufficient in terms of hydrogen.

3. A method as claimed in claim 1, wherein said combusting step generates hydrogen.

4. A method as claimed in claim 3, wherein said combusting step is gasifying.

5. A method as claimed in claim 3, wherein at least some of said hydrogen for upgrading is hydrogen generated in the combusting step.

6. A method as claimed in claim 1, wherein said upgrading comprises hydrotreating.

7. A method as claimed in claim 1, comprising adding a diluent to the upgraded hydrocarbon.

8. A method as claimed in claim 1, wherein said mobilised hydrocarbon mixture comprises water and hydrocarbon and said mixture undergoes separation to produce separated water and separated hydrocarbon.

9. A method as claimed in claim 8, wherein a diluent is added to said mobilised hydrocarbon mixture prior to said separation.

10. A method as claimed in claim 9, wherein said method is at least partially self-sufficient in terms of diluent for addition to said mobilised hydrocarbon mixture.

11. A method as claimed in claim 9, wherein said diluent comprises a lighter fraction obtained during fractionating of said recovered hydrocarbon mixture.

12. A method as claimed in claim 11, wherein said lighter fraction comprises naphtha, kerosene and/or light gas oils.

13. A method as claimed in claim 8, wherein said separated water is cleaned and recycled for steam generation.

14. A method as claimed in claim 13, which is at least partially self-sufficient in terms of water for steam generation.

15. A method as claimed in claim 1, wherein said coking is delayed coking or fluid coking.

16. A method as claimed in claim 1, wherein at least some of the CO.sub.2 generated in the method is captured and stored in a subterranean formation.

17. A method as claimed in claim 1, wherein at least a portion of the CO.sub.2 produced during said combustion is captured and stored.

18. A method as claimed in claim 1, wherein said method of recovery is steam assisted gravity drainage (SAGD).

19. A method as claimed in claim 18, comprising injecting steam produced in step (v) into said formation and/or applying said energy produced in step (v) to generate steam and injecting said steam into said formation.

20. A method as claimed in claim 1, wherein said method of recovery is in situ combustion.

21. A method as claimed in claim 20, comprising capturing at least a portion of CO.sub.2 from CO.sub.2 rich gas generated during in situ combustion.

22. A method as claimed in claim 21, comprising reinjecting a portion of said captured CO.sub.2 into the formation and/or storing at least a portion of said captured CO.sub.2 in a formation.

23. A method of recovering and processing a hydrocarbon mixture from a subterranean formation, comprising: (i) mobilising said hydrocarbon mixture; (ii) recovering said mobilised hydrocarbon mixture, wherein said mobilised hydrocarbon mixture comprises water and hydrocarbon; (iii) separating said mobilised hydrocarbon mixture to produce separated water and separated hydrocarbon, wherein a diluent is added to said mobilised hydrocarbon mixture prior to said separation; (iv) fractionating said separated hydrocarbon to produce a heavier fraction and at least one lighter fraction comprising naphtha, kerosene and/or light gas oils; (v) coking said heavier fraction to produce decoked hydrocarbon and coke; (vi) combusting said coke to generate steam and/or energy and CO.sub.2; (vii) adding a diluent from a diluent addition tank to the decoked hydrocarbon prior to upgrading in an upgrader, wherein said diluent addition tank is directly connected to said upgrader; and (viii) upgrading said decoked hydrocarbon by hydrogen addition to produce upgraded hydrocarbon; wherein said method is at least partially self-sufficient in terms of steam and/or energy and wherein at least some of said diluent for said mobilised hydrocarbon mixture and/or said diluent for said decoked hydrocarbon comprises said lighter fraction comprising naphtha, kerosene and/or light gas oils obtained directly during fractionating of said recovered hydrocarbon mixture.

24. A system for recovering and processing a hydrocarbon mixture comprising: (a) a well arrangement for a method of recovering hydrocarbon mixture comprising a production well; (b) a fractionator having an inlet for hydrocarbon mixture fluidly connected to said well arrangement, an outlet for a heavier fraction and an outlet for at least one lighter fraction comprising naphtha, kerosene and/or light gas oils; (c) a coker fluidly connected to said outlet for said heavier fraction of said fractionator and having an outlet for decoked hydrocarbon and an outlet for coke; (d) a combustion unit fluidly connected to said outlet for coke of said coker and having an outlet for steam and an outlet for CO.sub.2; (e) a diluent addition tank containing said at least one lighter fraction comprising naphtha, kerosene and/or light gas oils directly connected to the outlet for decoked hydrocarbon of said coker and having an inlet for said at least one lighter fraction comprising naphtha, kerosene and/or light gas oils and an outlet for a blend of said decoked hydrocarbon and said at least one lighter fraction comprising naphtha, kerosene and/or light gas oils; (f) an upgrader directly connected to said outlet for said blend of decoked hydrocarbon and said at least one lighter fraction comprising naphtha, kerosene and/or light gas oils of said diluent addition tank and having an inlet for hydrogen and an outlet for upgraded hydrocarbon; (g) a means for transporting steam generated by said combustion unit to a well arrangement; and (h) a means for transporting said at least one lighter fraction comprising naphtha, kerosene and/or light gas oils from said fractionator directly to said inlet for said at least one lighter fraction comprising naphtha, kerosene and/or light gas oils of said diluent addition tank.

25. A system as claimed in claim 24 comprising a diluent addition tank fluidly connected to the outlet for upgraded hydrocarbon of said upgrader.

26. A system as claimed in claim 24, wherein said upgrader is a hydrotreater.

27. A system as claimed in claim 24, wherein said combustion unit is a gasifier.

28. A system as claimed in claim 27, further comprising a means for transporting hydrogen generated by said gasifier to said inlet for hydrogen of said upgrader.

29. A system as claimed in claim 24 further comprising a separator for separating said recovered hydrocarbon into separated water and separated hydrocarbon, said separator being in between said well arrangement and said fractionator and having an inlet fluidly connected to said well arrangement, an outlet for separated hydrocarbon fluidly connected to said fractionator and an outlet for separated water.

30. A system as claimed in claim 29, wherein said outlet for separated water is fluidly connected to a water treatment unit for cleaning water for steam generation.

31. A system as claimed in claim 29, further comprising a means for transporting said at least one lighter fraction from said fractionator to said separator and/or to the line transporting recovered hydrocarbon mixture to said separator.

32. A system as claimed in claim 24, further comprising a separator for separating said recovered hydrocarbon into separated water and separated hydrocarbon, said separator being in between said well arrangement and said fractionator and having an inlet fluidly connected to said well arrangement, an outlet for separated hydrocarbon fluidly connected to said fractionator and an outlet for separated water, and a means for transporting said at least one lighter fraction from said fractionator to said separator and/or to the line transporting recovered hydrocarbon mixture to said separator.

33. A system as claimed in claim 24, further comprising a CO.sub.2 purifier fluidly connected to said outlet for CO.sub.2 of said combustion unit and an outlet connected to a subterranean formation for CO.sub.2 storage.

34. A system as claimed in claim 24, wherein said well arrangement comprises an injection well and at least one vent well for carrying out in situ combustion.

35. A system as claimed in claim 34, wherein said vent well is fluidly connected to said CO.sub.2 purifier.

36. A system as claimed in claim 34, wherein an outlet of said purifier is connected to said injection well.

Description

BRIEF DESCRIPTION OF THE DRAWINGS

(1) FIG. 1 is a schematic view of a cross section of an oil-bearing formation with SAGD well pairs suitable for carrying out the method of the invention;

(2) FIG. 2 is a flow diagram of a method and system of the invention showing the flow of each of steam, diluent, CO.sub.2 and water when SAGD is the method of recovery;

(3) FIG. 3 is a flow diagram of a method and system of the invention showing the flow of each of steam, hydrogen, diluent, CO.sub.2 and water when SAGD is the method of recovery;

(4) FIG. 4 is a schematic view of a cross section of an oil-bearing formation with a well arrangement for carrying out in situ combustion; and

(5) FIG. 5 is a flow diagram of a method and system of the invention showing the flow of each of steam, hydrogen, diluent, CO.sub.2 and water when in situ combustion is the method of recovery.

DETAILED DESCRIPTION OF PREFFERD EMBODIMENTS

(6) Referring to FIG. 1 it shows a cross section of a reservoir comprising SAGD well pairs. FIG. 1 shows the reservoir shortly after SAGD is started. A covering of overburden 1 lies above the hydrocarbon-containing portion of the reservoir 2. Each SAGD well pair 3, 4 comprises an injector well 5, 6 and a producer well 7, 8. The vertical separation (arrow A) between each well pair is about 5 m. The horizontal separation (arrow B) between each well pair is about 100 m. The injector wells 5, 6 are at the same depth in the reservoir and are parallel to each other. Similarly the producer wells 7, 8 are at the same depth in the reservoir and are parallel to each other. The producer wells are preferably provided with a liner (not shown) as is conventional in the art.

(7) In FIG. 1 steam has been injected into injector wells 5, 6 thus heated areas 9, 10 around each of the injector wells have been formed. In these areas the latent heat from the steam is transferred to the hydrocarbon and, under gravity, it drains downwards to producer wells 7, 8. From producer wells 7, 8 the mobilised hydrocarbon is pumped to the surface.

(8) Referring to FIG. 2 it shows the flow of each of steam, water, diluent and CO.sub.2 through the method and system of the invention when SAGD is used as the method of recovering hydrocarbon mixture.

(9) Considering first the flow of steam and water, initially steam is generated from natural gas by conventional methods (arrow a). The steam is injected via the injection wells of SAGD well pairs into a subterranean formation (arrow b) as described above in relation to FIG. 1. The steam mobilises heavy hydrocarbon present in the formation and heavy hydrocarbon is recovered at the surface from producer wells (arrow c). The mobilised hydrocarbon comprises a mixture of water and hydrocarbon and is routed to a bulk separator wherein the water and hydrocarbon are separated. Preferably diluent is added to the mixture prior to its entry to the separator (arrow n). The separated water is collected (arrow d) and sent to a treatment facility for cleaning so it can be reused for further steam generation (arrow e). The separated hydrocarbon is transported to a fractionator (arrow f) wherein naphtha, kerosene, light gas oils and/or heavy gas oils are removed (arrow g). The remaining hydrocarbon mixture is transported to a coker (arrow h) wherein coking takes place. The coking process produces decoked hydrocarbon that is transported out of the coker (arrow i) and coke that is transported to an oxycombustion unit (arrow j). Oxycombustion of the coke generates steam for use in hydrocarbon recovery and/or energy that is used to convert water to further steam (arrow k). Preferably the energy generated is used to convert the separated water from the separator into steam (arrow s). The method of the invention is advantageous because some of the energy inherently present in the hydrocarbon recovered is used to fuel the generation of steam for further hydrocarbon recovery. In this sense the method is at least partially self-supporting in terms of steam-generation.

(10) Considering now the flow of diluent through the method, as described above, the separated hydrocarbon is transported to a fractionator wherein a lighter fraction comprising naphtha, kerosene, light gas oils and heavy gas oils is removed (arrow g). The naphtha, kerosene, light gas oil and heavy gas oil obtained is used as the diluent that is added to the mixture of hydrocarbon and water prior to its entry to the separator (arrow n). Moreover the naphtha, kerosene, light gas oils and/or heavy gas oils obtained from the fractionator is used as a diluent for the decoked hydrocarbon mixture (arrow m). Thus the decoked hydrocarbon mixture produced in the coker unit is routed to a diluent addition tank (DAT) (arrow i) and blended with diluent (arrow m). The blend of diluent and hydrocarbon mixture that results is then transported to the upgrader, e.g. a hydrotreater (arrow u). The upgraded hydrocarbon is then transported to a diluent addition tank (DAT) (arrow v) and diluent is added (arrow w) to generate syncrude (arrow r).

(11) The recycling of the naphtha, kerosene, light gas oil and/or heavy gas oil from the heavy hydrocarbon for these purposes is highly advantageous. It avoids the need to transport and store an external diluent specifically for these purposes. Additionally because the diluent is generated from the hydrocarbon mixture into which it is being reintroduced, it is unlikely to cause any instability problems. A further advantage of the method is the compounds present in the heavy hydrocarbon are used in its processing. As above therefore, the method is at least partially self-supporting in terms of production of diluent for addition to crude hydrocarbon mixture and for production of syncrude.

(12) Considering now the flow of CO.sub.2 through the method, CO.sub.2 is generated at several points, namely during conversion of natural gas to steam and during combustion of coke. The CO.sub.2 is captured and transported (arrows y, z) to a purifier where it is cleaned. The CO.sub.2 is then pressurised, condensed and pumped to available CO.sub.2 subterranean formation sites (arrow x). A further advantage of the method of the invention is that less CO.sub.2 is released to the atmosphere than in traditional SAGD based processes.

(13) Referring now to FIG. 3 it shows the flow of hydrogen as well as each of steam, water, diluent and CO.sub.2 through the method of the invention when SAGD is used as method of recovering hydrocarbon mixture. There are two main differences between FIGS. 2 and 3 that are discussed below.

(14) First a gasifier is used instead of an oxycombustion unit as the combustion unit. Thus the coke produced in the coker is transported to a gasifier (arrow j) and the gasification process produces steam and/or energy, CO.sub.2 and hydrogen. The hydrogen is transported to the upgrader, typically a hydrotreater (arrow o) wherein it is used to upgrade the decoked hydrocarbon. The resulting upgraded hydrocarbon is transportable (arrow p). The upgraded hydrocarbon is blended with diluent in a diluent addition tank (DAT) (arrow q) to generate syncrude (arrow r). A further advantage of this embodiment is therefore that the hydrogen required for upgrading is generated from coke derived from the heavy hydrocarbon mixture. The method of the present invention is therefore self-sufficient or self-supporting in terms of hydrogen.

(15) The second difference between the method and system shown in the FIGS. 2 and 3 is that the decoked hydrocarbon is transported directly to an upgrader, i.e. without addition of diluent.

(16) Referring to FIG. 4 it shows a cross section of a reservoir comprising a well arrangement suitable for carrying out in situ combustion. An overburden 101 lies above the oil-bearing formation 102. A row of vertical injection wells 103 are drilled downward through the overburden 101. The injection wells 103 are completed in the oil-bearing formation 102. Vent wells 104 are also drilled through the overburden 101 and are completed in the oil-bearing formation 102, in an upper portion thereof. The vent wells 104 are drilled laterally spaced from the injection wells 103 so that the rows of injection wells 103 and rows of vent wells 104 are parallel. The production well 105 is substantially horizontal and is aligned with, and positioned below, the row of injection wells 103. The production well is located in a lower region of the oil-bearing formation. The production well is preferably provided with a liner (not shown) as is conventional in the art.

(17) In most cases it will be desirable to preheat the formation prior to commencing in situ combustion. This prepares the cold heavy hydrocarbon for ignition and develops enhanced hydrocarbon mobility in the reservoir. Preheating may be achieved by injecting steam through the injection wells 103 and optionally through the vent wells 104 and/or the production well 105. It is generally desirable to inject steam through all types of wells so fluid communication between the injection well 103, vent well 104 and production well 105 is achieved. Oil may be recovered in production well 105 during this preheating step. When the reservoir is sufficiently heated, combustion may be started and hydrocarbon recovery commenced.

(18) Oxygen-containing gas is injected into injection wells 103 to initiate combustion. Thereafter a combustion chamber forms around each injection well 103. The combustion chambers naturally spread and eventually form a continuous chamber that links all of the injection wells 103. The front of the combustion zone heats heavy hydrocarbon in its vicinity thereby increasing the hydrocarbon mobility and enabling it to flow. Under the forces of gravity, the heavy hydrocarbon 106 flows downwards towards production well 105. From there the heavy hydrocarbon is pumped to the surface facilities.

(19) At the same time as combustion, a gas layer 107 forms at the upper surface of the oil-bearing formation. This gas layer comprises CO.sub.2 rich combustion gases (their flow is represented by arrows 108) as well as CO.sub.2 injected as part of the oxygen-containing gas. A small amount of oxygen may also be present in gas layer 107. The gas will establish communication with the vent wells 104. Preferably the CO.sub.2-rich gases from the vent wells 4 are captured at the surface where they are treated as discussed below. After the combustion front has advanced a certain distance from the injection wells, the injection of oxygen containing gas is stopped. This will terminate the in situ combustion process.

(20) Referring to FIG. 5 it shows the flow of each of hydrogen, steam/energy, water, diluent and CO.sub.2 through the method of the invention when in situ combustion is used as the method of recovering hydrocarbon mixture. Many features of this method are the same as those discussed above in relation to the method based on SAGD. There are two main differences and these are discussed below.

(21) First when in situ combustion is used as the method of recovering hydrocarbon, steam is not continuously utilised in the process. Steam is generally used to pre-heat the formation prior to starting to combustion. Steam generated by gasification is therefore used for preheating. Alternatively the steam may be used in a SAGD method being carried out on a well in the vicinity. Preferably, however, gasification generates energy that can be used in another step of the process.

(22) Second in situ combustion generates large amounts of CO.sub.2. The CO.sub.2 rich gas is transported out of the formation via vent wells 104 (arrow 1) to the purifier (arrow 2). Once cleaned, the CO.sub.2 may be reinjected into the formation as part of the oxygen-containing gas for fuelling in situ combustion (arrow 3). Alternatively or additionally the CO.sub.2 may be stored in a formation (arrow 4).

(23) The method of the present invention has several advantages including: Oxycombustion of coke obtained from the hydrocarbon mixture generates steam and/or energy for generation of steam for use in further hydrocarbon recovery. Water for steam generation can be recycled water obtained by separating out and cleaning the water produced from the hydrocarbon formation along with the hydrocarbon mixture. Gasification of coke obtained from the hydrocarbon mixture generates hydrogen for upgrading the hydrocarbon mixture. Fractionation of the hydrocarbon mixture produces a lighter fraction, e.g. naphtha, kerosene and/or light gas oils, that can be used as diluent for the decoked hydrocarbon and/or upgraded hydrocarbon, e.g. in the generation of syncrude. Fractionation of the hydrocarbon mixture produces a lighter fraction, e.g. naphtha, kerosene and/or light gas oils, that can be used as diluent for the crude heavy hydrocarbon mixture to improve the separation process. Little, if any, CO.sub.2 is released to the atmosphere. Instead the CO.sub.2 is captured and stored in a formation.

(24) The method of the invention is at least partially self-supporting. The hydrocarbon mixture recovered from the subterranean formation provides diluent for the crude heavy hydrocarbon and for the generation of syncrude as well as at least some of the water and steam and/or energy required for steam generation for the hydrocarbon recovery. Preferred methods also provide at least some of each of the hydrogen required for upgrading.