INTERMITTENT FRACTURE FLOODING PROCESS

Abstract

A pressure-up blow-down method for recovering oil from an underground hydrocarbon formation, comprising the steps of: injecting an injection fluid into alternatingly-spaced multiple-induced fractures which extend radially outwardly and along a horizontal portion of a wellbore in the formation; ceasing injection of said injection fluid; recovering to surface oil which flows from remaining of the multiple induced fractures into the wellbore; and successively repeating the foregoing steps one or more times. Gas preferentially is initially used as the injection fluid and after one successive iteration water is then used. A sliding sleeve or sleeves which may be selectively slid open and closed within the wellbore in accordance with the method to allow and prevent, at various time periods in the method, fluid communication with fluid injection fractures and oil production fractures.

Claims

1. A method for sweeping oil from a hydrocarbon formation having a plurality of fractures therein extending radially outwardly from a wellbore therein using a single slidably-movable sleeve member, using an intermittent pressure-up blow-down procedure, comprising the steps of: (i) providing a substantially-horizontal wellbore within said hydrocarbon formation, said wellbore having therein a hollow cylindrical liner; (ii) providing a plurality of multiple induced fractures extending substantially radially outwardly from said horizontal wellbore, said multiple induced fractures contacting said wellbore and liner at spaced-apart points of contact and at correspondingly-spaced perforations in said liner; (iii) providing a single elongate hollow sleeve member longitudinally slidably moveable within said liner, said sleeve member having at least one aperture in an outer periphery thereof in communication with a hollow interior of said sleeve member; (iv) slidably moving said hollow sleeve member within said lined wellbore so as to align said at least one aperture therein with alternating of said multiple induced fractures so as to allow fluid communication with said wellbore and simultaneously prevent fluid communication between said wellbore and remaining of said multiple induced fractures by obstructing said remaining multiple induced fractures; (v) injecting an injection fluid into the hollow sleeve member and causing said injection fluid to flow into said alternating of said multiple induced fractures for a period of time to thereby pressure-up the formation; (vi) slidably moving said hollow sleeve member and said at least one aperture therein within said lined wellbore so as to then re-align said at least one aperture with remaining of said multiple induced fractures; (vii) collecting, within said slidable sleeve member, oil which drains downwardly from said remaining of said multiple inducted fractures into said wellbore, and recovering said oil to surface; and (viii) successively additionally repeating each of steps (iv)-(vii) one or more times.

2. The method as claimed in claim 1, wherein: step (ii) comprises providing said plurality of multiple induced fractures along said wellbore at uniformly spaced-apart points of contact with said wellbore and liner; step (iii) comprises providing a single elongate hollow sleeve member having a plurality of uniformly spaced-apart apertures therein, longitudinally spaced therealong in a spacing corresponding to spacing of alternating of said multiple induced fractures; step (iv) comprises slidably moving said hollow sleeve member within said liner so as to align said plurality of uniformly spaced-apart apertures therein with alternating of said multiple induced fractures; step (v) comprises injecting an injection fluid into the lined wellbore and hollow sleeve member and causing said injection fluid to flow into said alternating of said multiple induced fractures for a period of time to thereby pressure-up the formation, said alternating of said multiple inducted fractures when injected with said fluid comprising fluid injection fractures; step (vi) comprises slidably moving said hollow sleeve member and apertures therein within said lined wellbore so as to then re-align said spaced-apart apertures on said sidable sleeve member with remaining of said multiple induced fractures so as to form oil production fractures now aligned with said spaced-apart apertures on said hollow sleeve member; step (vii) comprises collecting, within said slidable sleeve member, oil which drains downwardly from said oil production fractures into said wellbore and recovering said oil to surface.

3. The method as claimed in claim 1, wherein said slidable sleeve is positioned on or coupled to the distal end of coiled tubing.

4. The method as claimed in claim 1, wherein said steps (v)-(vii) are initially conducted using a gas as the injection fluid, and successive iterations of steps (v)-(vii) are carried out using water as the injection fluid.

5. The method as claimed in claim 1, wherein method is carried out over a portion of a length of said lined wellbore.

6. The method as claimed in claim 1, wherein said step of re-aligning said hollow sleeve member in step (vi) is carried out by insertion downhole of a tool at the distal end of coil tubing, which upon actuation allows displacement of said sliding sleeve member.

7. The method as claimed in claim 1, comprising the further step after step (vii) but prior to commencing or recommencing step (v), of flushing oil remaining in said lined wellbore from the lined wellbore by draining said injection fluid in said alternating of said multiple induced fractures into said wellbore, and producing said fluid and any remaining oil in said wellbore to surface.

8. The method as claimed in claim 1, comprising the further step, prior to commencing or recommencing step (v), of flushing oil remaining in said lined wellbore from the lined wellbore by injecting said injection fluid at a toe of said horizontal portion via a tubing in said lined wellbore extending to said toe thereof, and producing same to surface.

9. The method as claimed in claim 1, wherein the injection fluid is a gas.

10. The method as claimed in claim 9, wherein said gas is miscible in oil.

11. The method as claimed in claim 1, wherein the injection fluid is a gaseous fraction which is obtained from said produced oil.

12. The method as claimed in claim 11, wherein said gas fraction is obtained from said produced oil by subjecting said produced oil to increased temperature and/or reduced pressure, to thereby flash volatile gaseous components within said produced oil for use of such volatile gaseous components as the injection fluid.

13. The method as claimed in claim 11, wherein the gas fraction is enriched in C2-C5 components.

14. The method as claimed in claim 1, wherein the injection fluid comprises a gas selected from the group of gases consisting of natural gas, gases contained within and obtained from said produced oil, CO2, and mixtures thereof.

15. The method as claimed in claim 1, wherein a portion of oil which is produced in accordance with one or more of such methods is heated and used to flash volatile gaseous components therein to thereby provide additional gaseous components to the injected fluid.

16. The method as claimed in claim 1, wherein the injected fluid is water with or without chemical additives.

17. The method as claimed in claim 1, wherein the injected fluid includes both water and gas.

18. The method as claimed in claim 1, wherein the wellbore is a vertical, slant or horizontal wellbore.

19. The method as claimed in claim 1, wherein said method is first commenced at any time in a lifecycle of a completed hydrocarbon reservoir.

20. The method as claimed in claim 1, said injecting of said injection fluid and pressuring up said formation in step (v) is carried out over a period extending from one day to 1 year.

21. The method as claimed in claim 1, wherein said period of time in step (vii) for said recovering of said produced fluids is carried out over a period extending from one month to 10 years.

22. The method as claimed in claim 1, wherein fluid pressure within said lined wellbore is equalized over its length.

23. The method as claimed in claim 2, wherein said perforations in said liner at said points of contact with said fluid injection fractures and said oil production fractures have a larger cross-sectional area proximate a toe of said wellbore as compared to cross sectional area of perforations in said liner more proximate a heel of said wellbore.

24. The method as claimed in claim 1, wherein injection of said fluid and production of said oil are accomplished via flow thereof through a perforated liner inserted within and extending substantially over a horizontal length of said portion of the wellbore, said perforated liner having perforation patterns therein configured so as to equalize fluid pressure differential applied to said multiple induced fractures over a length of said wellbore.

25. An intermittent pressure-up, blow-down method to recover oil from an underground hydrocarbon formation having a wellbore and having multiple induced fractures extending radially outwardly from said wellbore and longitudinally spaced along a portion of a length of said lined wellbore, using a single elongate hollow sliding sleeve member having a plurality of apertures therein longitudinally spaced along a length of said hollow sleeve member, comprising the steps of: (i) providing a liner within said wellbore having perforations therein aligned with said multiple inducted fractures along said wellbore; (ii) slidably moving said elongate hollow sleeve member longitudinally within said lined wellbore, so as to align said apertures in said sleeve member with corresponding alternately spaced of said multiple induced fractures to form a plurality of fluid injection fractures in fluid communication with said wellbore, and simultaneously obstructing perforations in said liner aligned with remaining of said multiple induced fractures spaced along said wellbore so as to form a plurality of oil production fractures which are temporarily prevented from fluid communication with said wellbore; (iii) injecting an injection fluid into the lined wellbore and causing said injection fluid to flow into said fluid injection fractures for a period of time, to thereby pressure-up the formation; (iv) slidably repositioning said hollow sleeve member so as to prevent fluid communication between said fluid injection fractures and an interior of said lined wellbore, and simultaneously by said slidable movement allowing fluid communication between said oil production fractures and said interior of said lined wellbore; (v) collecting oil which flows into said lined wellbore from said oil production fractures, and producing same to surface; and (vi) successively additionally repeating each of steps (i)-(iv) one or more times.

26. The method as claimed in claim 25, wherein said sleeve member is further provided with at least one pair of packers or seal members on respectively mutually opposite sides of each of said plurality of apertures therein.

27. The method as claimed in claim 26, having a further step, subsequent to step (iv) but prior to commencing or recommencing step (ii), of flushing oil remaining in said lined wellbore by injecting said injection fluid at a toe of the horizontal portion via a tubing in said lined wellbore extending to said toe thereof, and producing same to surface.

28. A pressure-up, blow-down method to sweep oil from an underground hydrocarbon formation and recover same to surface, said hydrocarbon formation having at least four uniformly-spaced induced fractures spaced along and contacting a portion of a length of lined or unlined horizontal wellbore situated in said hydrocarbon formation, said induced fractures extending substantially radially outwardly and upwardly from said wellbore, comprising the steps of: (i) providing a coil tubing having proximate a distal end thereof at least two apertures therein, said apertures spaced along a longitudinal length thereof in accordance with spacing of alternating of said induced fractures along said horizontal wellbore; (ii) providing a plurality of pairs of actuatable packer members, each member of each pair positioned on said coil tubing so as to bound each aperture on respectively opposite sides thereof; (iii) positioning said coil tubing, apertures therein, and pairs of packer members bounding said apertures along said horizontal wellbore such that said apertures in said coil tubing are each simultaneously aligned with alternatingly spaced of said induced fractures and further simultaneously positioned so as to prevent remaining of said induced fractures from having fluid communication with an interior of said coil tubing via said apertures therein; (iv) actuating said packers within said horizontal wellbore so as to prevent fluid communication along said wellbore and between remaining of said induced fractures other than via said coil tubing; (v) injecting a fluid within said coil tubing, and allowing said fluid to flow into said alternatingly spaced of said inducted fractures, so as to pressure up said hydrocarbon formation; (vi) de-actuating said packers; (vii) moving said coil tubing and apertures therein bounded by said pairs of packers either uphole or downhole so as to simultaneously re-align said apertures in said coil tubing with remaining of said induced fractures along said horizontal wellbore; and (viii) collecting oil which drains downwardly from said remaining induced fractures and passes into said coil tubing via said at least two apertures therein and producing same to surface.

29. The method as claimed in claim 28, further comprising the step, after step (viii), of successively additionally repeating each of steps (iii)-(vii) one or more times.

30. The method as claimed in claim 29, wherein said steps (v)-(viii) are initially conducted using a gas as the injection fluid, and successive iterations of steps (v)-(viii) are carried out using water as the injection fluid.

31. The method as claimed in claim 28, wherein the injection fluid is a gas.

32. The method as claimed in claim 31, wherein said gas is miscible in oil.

33. The method as claimed in claim 28, wherein the injection fluid is a gaseous fraction which is obtained from said produced oil.

34. The method as claimed in claim 33, wherein said gas fraction is obtained from said produced oil by subjecting said produced oil to increased temperature and/or reduced pressure, to thereby flash volatile gaseous components within said produced oil for use of such volatile gaseous components as the injection fluid.

35. The method as claimed in claim 33, wherein the gas fraction is enriched in C2-C5 components.

36. The method as claimed in claim 31, wherein the injection fluid comprises a gas selected from the group of gases consisting of natural gas, gases contained within and obtained from said produced oil, CO.sub.2, and mixtures thereof.

37. The method as claimed in claim 28, wherein a portion of oil which is produced in accordance with one or more of such methods is heated and used to flash volatile gaseous components therein to thereby provide additional gaseous components to the injected fluid.

38. The method as claimed in claim 1, wherein the injected fluid is water with or without chemical additives.

39. The method as claimed in claim 1, wherein the injected fluid includes both water and gas.

40. The method as claimed in claim 28, wherein said method is first commenced at any time in a lifecycle of a completed hydrocarbon reservoir.

41. The method as claimed in claim 28, said injecting of said injection fluid and pressuring up said formation in step (v) is carried out over a period extending from one day to 1 year.

42. The method as claimed in claim 28, wherein said period of time in step (viii) for said recovering of said produced fluids is carried out over a period extending from one month to 10 years.

Description

BRIEF DESCRIPTION OF THE DRAWINGS

[0079] Further advantages and other embodiments of the invention will now appear from the above along with the following detailed description of the various particular embodiments of the invention, taken together with the accompanying drawings each of which are intended to be non-limiting, in which:

[0080] FIG. 1 is a schematic diagram showing the initial step in one embodiment of the Intermittent Fracture Flooding process of the present invention, where fluid communication between the wellbore and the alternatingly-spaced multiple induced fluid injection fractures has initially been established, and fluid communication between alternatingly-spaced fluid production fractures and the wellbore has been prevented/shut-in by movement of associated sliding sleeves within the wellbore;

[0081] FIG. 2 is a schematic diagram depicting a subsequent step in the Intermittent Fracture Flooding process of FIG. 1, wherein communication between the wellbore and the alternatingly-spaced multiple induced oil production fractures is established, and fluid communication between alternatingly-spaced fluid injection fractures and the wellbore is prevented/shut-in, again by movement of sliding sleeves in the wellbore;

[0082] FIG. 3 is a schematic diagram showing of an initial step in a second embodiment in the Intermittent Fracture Flooding process of the present invention, wherein communication between the wellbore and the alternatingly-spaced multiple induced fluid injection fractures is established, and fluid communication between alternatingly-spaced oil production fractures and the wellbore is prevented, by sliding movement of a single sliding sleeve situated at the respective locations of contact of all of the alternatingly-spaced fluid injection fractures and oil production fractures along the wellbore;

[0083] FIG. 4 is a schematic diagram depicting a subsequent step in the Intermittent Fracture Flooding process of FIG. 3, wherein communication between the wellbore and the alternatingly-spaced multiple induced oil production fractures is established, and fluid communication between alternatingly-spaced fluid injection fractures and the wellbore is prevented/shut-in, again by movement of the single sliding sleeve in the wellbore;

[0084] FIG. 5 is a schematic diagram depicting a further optional step in any of aforementioned methods of the present invention, wherein after producing for a time oil from the alternatingly-spaced oil production fractures, a coiled tubing may be inserted to the toe of the wellbore and a flushing fluid injected via said coil tubing into the toe of the wellbore to thereby flush oil within the wellbore and recover same to surface, prior to injecting the injection/driving fluid in the wellbore for injection into the alternatingly-spaced fluid injection fractures;

[0085] FIG. 6 is a schematic diagram depicting an initial step in another embodiment of the method of the present invention, which method employs a series of sliding sleeves regulating fluid communication only between the wellbore and the oil production fractures, wherein the sliding sleeves are initially in the closed position preventing injection of injection fluid into the oil production fractures and wherein such injected fluid supplied to the wellbore flows into the fluid injection fractures;

[0086] FIG. 7 is a schematic diagram of the embodiment of the method shown in FIG. 10, wherein supply of injection fluid to the wellbore has been ceased, and the sliding sleeves have now been moved to the open position and oil is flowing into the wellbore from the oil production fractures and being produced to surface;

[0087] FIG. 8 is one example of a sliding sleeve within the casing for allowing and preventing, when in an open and closed position respectively, oil flowing into the wellbore from the oil production fractures within the formation, showing such sliding sleeve in the closed position;

[0088] FIG. 9 is a depiction of the sliding sleeve as shown in FIG. 8, but in the open position uncovering a port in the wellbore liner;

[0089] FIG. 10 is a schematic diagram depicting an initial step in another embodiment of the method of the present invention which employs a series of packers and two separate and distinct coil tubings, wherein a fluid injectant is supplied via a first tubing to alternatingly-spaced of the multiple induced injection fractures isolated from remaining alternately-spaced fractures;

[0090] FIG. 11 is a schematic diagram depicting a subsequent step in the Intermittent Fracture Flooding process of FIG. 10, wherein supply to fluid injectant via the first tubing is halted, and oil is allowed to flow from remaining alternating fractures into the second of the coil tubing, and produced to surface;

[0091] FIG. 12 is a schematic diagram of the initial fluid injection step in another embodiment of the method of the present invention, which employs a series of packers and a single coil tubing, wherein a fluid injectant is supplied via the coil tubing to areas bounded by a series of packers and thus into the fluid injection fractures, and oil production fractures are shut-in/isolated;

[0092] FIG. 13 is a schematic diagram of the subsequent oil production step in the method of FIG. 12, wherein the coil tubing and packers are move slightly uphole (or downhole) to thus align apertures in the coil tubing (and intermediate the packers) with the oil production fractures, and shut in the fluid injection fractures; and

[0093] FIG. 14 is a single combined series of graphs comparing oil recovery factor as a function of time for a hydrocarbon formation, for: [0094] a) continuous water Fracture Flooding (prior art); [0095] b) continuous gas Fracture Flooding (prior art); [0096] c) primary oil recovery (prior art); [0097] d) Intermittent Fracture Flooding in accordance with a the method of the present invention, using gas only as the injection fluid; [0098] e) Intermittent Fracture Flooding for the first stage, then Intermittent water Fracture Flooding; and [0099] f) Intermittent Fracture Flooding using only water as the injection fluid.

[0100] In obtaining each of the aforementioned results a)-e), two (2) years of primary production were undertaken, followed by [with the exception of curve (c)] with injection of gas or water, as the case may be, for a period of 4 months, continuously or intermittently, as the case may be.

DETAILED DESCRIPTION OF SOME PREFERRED EMBODIMENTS

[0101] FIG. 1 shows a schematic diagram of an initial step, and FIG. 2 a subsequent step, of in one embodiment of the intermittent pressure-up blow-down method 100 of the present invention for recovering oil from an underground hydrocarbon formation 1 having a lined wellbore 9 therein.

[0102] FIG. 3 similarly show a schematic diagram of an initial step, and FIG. 4 a subsequent step, of another embodiment of the intermittent pressure-up blow-down method 100 of the present invention.

[0103] In all embodiments, method 100 of the present invention is adapted to be worked in a hydrocarbon formation 1, namely a hydrocarbon-bearing deposit 1 typically situated between an upper non-hydrocarbon-containing layer 3, and a lower non-hydrocarbon-containing layer 5 typically consisting of cap rock. Hydrocarbon formation 1 may have a pre-existing wellbore 9 or a newly-drilled lined wellbore 9, and has such formation 1 has been fractures along a portion (preferably but not necessarily a horizontal portion) of the wellbore 9 been completed by any of the known hydraulic fracturing methods so as to have created multiple induced fractures 40a, 40b spaced along a portion of a length of wellbore 9 having liner 10 therein. Multiple induced fractures 40a, 40b extend radially outwardly from such lined wellbore 9.

[0104] In the embodiment of the method shown in FIGS. 1 & 2, a series of sliding sleeves 30a, 30b are provided installed along a portion of the length of a lined wellbore 9, namely along the wellbore casing.

[0105] An actuator tool, as commonly known in the art (not shown), may be inserted down the wellbore 9 at the end of coil tubing (not shown) so as to initially actuate/move sliding sleeves 30a to an open position. Alternatively sliding sleeves 30a may be initially installed along lined wellbore 9 in an open position when such wellbore casing is inserted in the well, to initially allow fluid communication between wellbore 9 and fluid injection fractures 40a.

[0106] Similarly, as regards sliding sleeves 30b which regulate fluid communication between wellbore 9 and oil production fractures 40b, such sliding sleeves 30b may be initially installed along lined wellbore 9 in a closed position when such wellbore casing is inserted in the well, to initially prevent fluid communication between wellbore 9 and oil production fractures 40b, and may be subsequently opened when desired by the insertion downhole of an actuation tool as discussed.

[0107] Alternatively, sliding sleeves 30b may be of the type shown in FIGS. 8 & 9, wherein supply of a high pressure fluid within wellbore lining 9 enters port 20 and cavity 18, causing compression of spring 15 in cavity 14 and movement of sliding sleeve 30b to cover port 8 thereby shutting in oil production fractures 40b from fluid communication, as shown FIG. 8 and in FIG. 1.

[0108] Injectant fluid 70, under relative pressure ΔP, can then be supplied to fluid injection fractures 40a for a time sufficient to pressure up formation 1 by injectant fluid 70 driving oil and associated hydrocarbons in such formation 1 towards alternatingly spaced oil production fractures 40b.

[0109] Thereafter, at a time when formation 1 has become sufficiently pressured up, the supply of injectant fluid to wellbore 9 and fluid injection fractures 40a is ceased. Cessation of fluid pressure in wellbore 9, if sliding sleeves 30b are of a type shown in FIG. 9, by operation of spring 14 in cavity 15, causes sliding sleeves to then be moved so as to uncover associated ports 8 thereby allowing oil to flow from the hydrocarbon formation 1 into wellbore 9 via oil production fractures 40b so as to then be capable of being flowed to surface 4 via wellbore 9. Alternatively, sliding sleeves 30b, if not of the type shown in FIGS. 8, 9 and requiring physical manipulation, may likewise be moved to the open position by the same actuation tool inserted down the wellbore 9 to close sliding sleeves 30a, to then allow the wellbore 9 to receive oil from oil production fractures 40b.

[0110] Thereafter, upon the rate of recovery of oil 72 from wellbore 9 falling off as oil is produced, the above method may be repeated, so as to re-pressure the formation 1 and again drive additional oil and hydrocarbons to oil production fractures for subsequent recovery.

[0111] FIGS. 3 & 4 show another embodiment of the above method, wherein as shown in FIG. 3 the initial opening of ports 7 allowing supply of injectant fluid to fluid injection fractures 40a and the initial shutting-in of oil production fractures 40b, is accomplished by initially positioning a sliding sleeve 30 having ports 30a′ and 30b′ therein in a first position allowing fluid communication between wellbore 9 and fluid injection fractures 40a via ports 30a′ therein, and simultaneously isolating oil production ports 40b by preventing from fluid communication by closing ports 30b′ and thereby preventing fluid communication with wellbore 9.

[0112] To transition to the oil recovery phase of the Intermittent Recovery Process of the present invention, sleeve 30 is slidably moved (via an actuation tool as described above being inserted downhole) to a second position, as shown in FIG. 4, wherein sliding sleeve 30 then prevents fluid communication via ports 30a′ therein with fluid production channels 40a but allows fluid communication of oil production channels 40b with wellbore 9 via ports 30b′ therein.

[0113] FIG. 5 shows an optional additional step in the method of the present invention, wherein after completion of the oil production phase (FIG. 2, FIG. 4, FIG. 7, FIG. 11 & FIG. 13) but prior to the re-injection of fluid injection phase (FIG. 1, FIG. 3, FIG. 6, FIG. 10 & FIG. 12), residual oil remaining in wellbore 9 is flushed by injecting the injectant fluid 70 at the toe 80 of the wellbore 9 via a coil tubing 82 extending to toe 80, and re-producing such injectant fluid back to surface 4. In such manner residual oil is produced to surface 4, rather than being intermingled with injection fluid 70 and being re-injected into formation 1 during the subsequent fluid injection phase.

[0114] Each of the embodiment shown in FIGS. 1 & 2 and the embodiment shown in FIGS. 3 & 4 employ a shut-in means such as sliding sleeves 30a, 30b shown in FIG. 1, 2 or a single sliding sleeve 30 having ports 30′ thereon as shown in FIGS. 3 & 4, for shutting in (when desired) each of the associated fluid injection fractures 40a and oil production fractures 40b, respectively, and preventing fluid communication of each with wellbore 9.

[0115] It is not necessary, however, in order to practice the method of the present invention, for there to be installed sliding sleeves 30a, 30b or a single sliding sleeve 30 to regulate fluid communication between both the fluid injection fractures 40a and the oil production fractures 30b.

[0116] Rather, in a further embodiment of the method of the present invention, as shown in FIG. 6 (fluid injection) & FIG. 7 (oil production), sliding sleeves 30b or a sliding sleeve 30 may simply be provided to regulate flow of fluid only through ports 8 in lined wellbore 9 so as to thereby only regulate fluid communication of the oil production fractures 40b with the wellbore 9.

[0117] No regulation of fluid communication of wellbore fluids with fluid injection fractures 40a in this particular method is thus required.

[0118] In such embodiment/method, sliding sleeves 30b or sliding sleeve 30 may be of the type which are opened/closed by means of an actuation tool (not shown).

[0119] Alternatively, sliding sleeves 30b may be of the type as shown in FIGS. 8, 9 wherein when fluid injectant under a fluid pressure P is supplied to wellbore 9 associated sliding sleeves 30b are caused to move in the manner described above so as to cover ports 8 and thereby prevent injectant fluid being injected into oil production fractures 40b. In such manner the injectant fluid is only supplied via the open ports 7 in wellbore liner 9 to the fluid injection fractures 40a during the pressure-up phase of the method.

[0120] Upon cessation of the first pressuring-up phase of this refined method, and the transition to the second blow-down phase wherein supply of pressurized injectant fluid 70 is ceased, such absence of pressure causes springs 14 (ref. FIG. 9) to return sliding sleeve to an open position uncovering port 8 in wellbore liner 9, thereby allowing oil 72 to flow into wellbore 9 via oil production fractures 40b and be produced to surface 4.

[0121] The multiple sliding sleeves 30a, 30b (FIGS. 1, 2) and the single sliding sleeve 30 of FIG. 3, 4, and the further single series of sliding sleeves 30b of FIGS. 6 & 7 regulating fluid communication only with oil production fractures 40b, are all simply one manner of isolating respectively at least the oil production fractures 40b from wellbore 9 when injecting injectant fluid 70.

[0122] The present invention further embodies and encompasses methods of intermittently and repeatedly pressuring up and blowing down a reservoir, in the manner described herein, without using a sliding sleeve or sleeves.

[0123] In this regard, FIGS. 10-11 and FIGS. 12-13 each show two further alternative embodiments of the method 100 of the present invention where no sliding sleeves are used, and instead a series of packer 25 are used to effect isolation of the oil production fractures 40b from the fluid injection fractures 40a.

[0124] FIGS. 10 & 11 show a method using a series of (preferably expandable) packer elements 25 through which separate dual tubing, namely a fluid injectant coil 43 and a separate oil production coil 44 passes. As seen from FIG. 10 (the initial fluid injectant phase of the method), the packer elements 25 and coils 43, 44 are placed downhole in lined wellbore 9, with packer elements 25 on opposite sides of ports 7 and 8 along wellbore liner 9. Injectant fluid is first injected into coil 43, and flows out apertures 63 and thus into fluid injection fractures 40a via ports 7 in wellbore liner 9.

[0125] Upon pressuring up of formation, injection of injectant fluid 70 is ceased (FIG. 11). Thereafter, as seen from FIG. 11 (i.e. the second production phase of the method), produced oil 72 flows into ports 68 in coil 44 via ports 8 in lined wellbore 9, and is produced to surface 4. Upon the rate or quantity of oil 72 from formation 1 dropping below a predetermined rate, the aforementioned steps are again repeated.

[0126] FIGS. 12 & 13 similarly show another method using a series of (preferably expandable) packer elements 25 through which passes a single coil 45, which single coil 45 is alternately used first as a fluid injectant conduit and subsequently as an oil production conduit. No sliding sleeves are needed in this embodiment.

[0127] As seen from FIG. 12 (the initial fluid injectant phase of the method), the packer elements 25 and single coil 45 are initially run downhole in lined wellbore 9, with packer elements 25 positioned along the lined wellbore 9 on opposite sides of ports 7 and 8 along wellbore liner 9.

[0128] As seen from FIG. 12, injectant fluid is first injected into coil 45 and flows out apertures 65 therein and thus into fluid injection fractures 40a via ports 7 in wellbore liner 9.

[0129] After a time and upon pressuring up of formation 1, injection of injectant fluid 70 is ceased.

[0130] The series of packer elements 25 and coil 45 are together pulled slightly uphole, to now align apertures 65 in coil 45 with ports 8 in lined wellbore 9, thereby allowing oil 72 to flow into ports 65 in coil 45, and thereafter is produced to surface 4.

EXAMPLES

Example 1

[0131] Gas was employed as the injection fluid for all four stages, as described below.

[0132] A first stage comprising a primary depletion stage of 2 years and a period of 4 months where gas was injected into the formation.

[0133] Specifically, after a period of 2-years of primary depletion, and with reference to FIGS. 1 & 2, sliding sleeves 30b were closed, isolating associated oil production fractures 40b from the horizontal wellbore 9. Then the sliding sleeves 30a were opened and gas (methane) was injected into the wellbore 9 from the surface 4, which gas entered thus-opened fluid injection fractures 40a and penetrated the adjacent reservoir matrix 5, thus moving oil forward and pressurizing the reservoir 6 to a target maximum value, limited so as to not fracture the rock further. After 4-months of injection, when the gas injection rate had fallen to a pre-determined minimum, injection is deemed complete and fluid injection fractures 40a were shut-in by closing associated sliding sleeves 30a, while the oil production fractures 40b were opened to the wellbore 9 by moving sliding sleeves 30b to the open position, for a period of 2-years.

[0134] The second stage (stage 2) was begun by closing sleeves 30b thereby isolating the oil production fractures 40b, and opening sliding sleeves 30a to allow fluid communication between wellbore 9 and fluid injection fractures. For a brief period, the fluid injection fractures 30a were produced through sleeves 30a into the wellbore 9 and to surface 4 in order to flush the wellbore 9 of production fluids. Thereafter, gas was injected into the fluid injection fractures 40a via wellbore 9 for a period of 4 months. Sliding sleeves 30a were subsequently closed thereby isolating the associated fluid injection fractures 40a, followed by opening of sleeves 30b to allow oil to flow into wellbore 9 via oil production fractures 40b now opened to fluid communication with wellbore 9, to allow wellbore to produce and flow such oil to surface 4.

[0135] The above procedures of stage 2 were repeated for two more stages (stages 3 & 4), with stages 3 & 4 each being a successive iteration of above stage 2.

Example 2

[0136] The procedures of Example 2 were the same as for Example 1, except that the injection fluid was gas for the first stage and water for the next 3 stages.

Example 3

[0137] The procedures of Example 3 were the same as for Example 1, except that the injectant was water for all stages.

Numerical Simulations of Examples 1-3 and Additional Examples for Comparative Purposes

[0138] In order to demonstrate the efficacy of the intermittent injection methods of the present invention over the prior art, six (6) cases of numerical simulations were conducted using the Computer Modelling Group's STARS reservoir modeling software starting with a standard CMG model as modified, with the parameters of Table 1.

[0139] Above Examples 1-3 were simulated using the above computer modelling software, as well as three (3) prior art cases: primary recovery, continuous gas injection, and continuous water injection, using the software parameter inputs and conditions set out in Table 1 below:

TABLE-US-00001 TABLE 1 Numerical simulation parameters Value Units Reservoir Temperature 73 Degree Celsius pressure 17,000 kPa Maximum safe injection pressure 23,000 kPa Horizontal permeability 0.50 mD Vertical permeability 0.05 mD Oil saturation 50 % Water saturation 50 % Fracture permeability 2000 mD Oil density 45 Degree API Gas-oil-ratio 64 Dissolved in oil Model Parameters Grid block size, I, j, k 1, 5, 1 meters Number Grid blocks, I, j, k 200, 10, 40 number (¼ element of symmetry) Full model volume 1.6E06 Cubic meters Bottom-hole pressure 100 kPa

[0140] A generic “tight” reservoir having light oil (Oil density of 45° API) was assumed, and the model employed an element of symmetry representing ¼ of the affected reservoir.

[0141] For all simulations, the reservoir was first produced under primary production for 2-years. Then 4-stages of injection and production were conducted. The injection periods were 4-months duration and the production periods were 2-years duration. This is not to limit the possible injection or production intervals, which will depend upon the availability of injection fluids, the spacing of the fractures, the fluid injection rates, reservoir permeability and other factors familiar to those knowledgeable in the art. The present Intermittent Fracture Flooding Process can be applied at any time during the life of the well, including at start-up.

[0142] The results of the aforesaid simulated scenarios are graphically displayed in FIG. 6.

[0143] In a preferred embodiment of the method of the present invention and referring to line e) in FIG. 6, a first stage of gas injection is conducted because this provides the largest increase in oil rate and oil recovery factor relative to the primary recovery factor.

[0144] However, as may be seen from FIG. 6, in subsequent stages the advantage of gas injection over water injection is only slight [cf. line ‘a’ as compared to line ‘b’, respectively)] and indeed in later stages water injection has a higher oil recovery factor. Accordingly, since gas compression costs are considerably higher than for water injection with a pump, it is more economical to switch to water injection after the first stage.

[0145] In a more preferred embodiment, the option of miscible gas injection for all stages can be undertaken. This can be accomplished with the produced fluids in at least two ways. Firstly, the produced gas can be re-cycled to establish multiple-contact miscibility, and secondly, the produced light oil (e.g. Bakken oil: 42 degrees, 7.2% C2-C5) can be heated to an appropriate temperature, and/or subjected to decreased pressure to provide light hydrocarbons to the re-injected gas, so that a miscible injection gas flood can be established faster or even immediately.

[0146] While it might seem imprudent to deliberately flash off some of the oil product, it should be recalled that light tight oil from the Bakken and Eagle Ford formation is problematic from the perspective of shipping safety as demonstrated by at least two recent devastating rail car explosions that were attributed to the high Reid vapor pressure of oil from those formations. The removal of light components from the sales oil would reduce the oil vapor pressure and improve transportation safety. In a further embodiment the Intermittent Fracture Flooding Process can also be enhanced by including within the horizontal well pressure-equalizing equipment such as a perforated injection and production tubing with holes strategically designed to equalize pressure within the annular space.

[0147] The above description of some embodiments of the present invention is provided to enable any person skilled in the art to make or use the present invention.

[0148] For a complete definition of the invention and its intended scope, reference is to be made to the summary of the invention and the appended claims read together with and considered with the detailed description and drawings herein on a purposive interpretation thereof.