Hydraulic feature initiation and propagation control in unconsolidated and weakly cemented sediments
원문보기
IPC분류정보
국가/구분
United States(US) Patent
등록
국제특허분류(IPC7판)
E21B-043/26
E21B-043/25
출원번호
US-0685019
(2007-03-12)
등록번호
US-7404441
(2008-07-29)
발명자
/ 주소
Hocking,Grant
출원인 / 주소
Geosierra, LLC
대리인 / 주소
Smith, Gambrell & Russell
인용정보
피인용 횟수 :
12인용 특허 :
68
초록▼
A method and apparatus for initiating and propagating a vertical hydraulic fracture in unconsolidated and weakly cemented sediments from a single bore hole to control the fracture initiation plane and propagation of the hydraulic fracture, enabling greater yield and recovery of petroleum fluids from
A method and apparatus for initiating and propagating a vertical hydraulic fracture in unconsolidated and weakly cemented sediments from a single bore hole to control the fracture initiation plane and propagation of the hydraulic fracture, enabling greater yield and recovery of petroleum fluids from the formation. An injection casing with multiple fracture initiation sections is inserted and grouted into a bore hole. A fracture fluid carrying a proppant is injected into the injection casing and opens the fracture initiation sections to dilate the formation in a direction orthogonal to the required fracture azimuth plane. Propagation of the fracture is controlled by limiting the fracture fluid injection rate during fracture initiation and propagation and maintaining a minimum fracture fluid viscosity. The injection casing initiation section remains open after fracturing providing direct hydraulic connection between the production well bore, the permeable proppant filled fracture and the formation.
대표청구항▼
What is claimed is: 1. A method for creating a vertical hydraulic fracture in a formation of unconsolidated and weakly cemented sediments, comprising: a. drilling a well bore in the formation to a predetermined depth; b. installing an injection casing having an inner and outer surface in the bore h
What is claimed is: 1. A method for creating a vertical hydraulic fracture in a formation of unconsolidated and weakly cemented sediments, comprising: a. drilling a well bore in the formation to a predetermined depth; b. installing an injection casing having an inner and outer surface in the bore hole at the predetermined depth; c. dilating the casing and the formation in a preferential direction; d. injecting a fracture fluid into the injection casing with sufficient fracturing pressure to initiate a hydraulic fracture at an azimuth orthogonal to the direction of dilation; e. limiting the rate of fracture fluid injection to initiate the hydraulic fracture so that Re is less than 100; and f. maintaining the fracturing fluid viscosity to be greater than 100 centipoise at the initiated fracture fluid shear rate. 2. The method of claim 1, wherein the method further comprises: a. installing the injection casing at a predetermined depth in the well bore, wherein an annular space exists between the outer surface of the casing and the bore hole, b. filling the annular space with a grout that bonds to the outer surface of the casing to form a grout annulus, wherein the casing has multiple initiation sections separated by a weakening line so that the initiation sections separate along the weakening line under the fracturing pressure. 3. The method of claim 2, wherein the fracture fluid dilates the casing, the grout annulus and the formation to initiate the fracture in the formation at the weakening line. 4. The method of claim 3, wherein the casing comprises two initiation sections with two directions of dilation. 5. The method of claim 4, wherein each hydraulic fracture creates individual opposing wings, and wherein the casing enables controlling the rate of fracture fluid injection into each individual opposing wing of the hydraulic fractures thereby controlling the geometry of the hydraulic fractures. 6. The method of claim 4, wherein the casing is two-thirds of the height of the completed interval to be hydraulically fractured. 7. The method of claim 4, wherein the casing is one-half of the height of the completed interval to be hydraulically fractured. 8. The method of claim 4, wherein the casing is one-third of the height of the completed interval to be hydraulically fractured. 9. The method of claim 4, wherein the initiation sections remain separated after dilation of the casing by the fracture fluid to provide hydraulic connection of the fracture with the well bore following completion of hydraulic fracturing. 10. The method of claim 4, wherein the fracture fluid comprises a proppant and the initiation sections each contain well screen sections separating the proppant in the hydraulic fracture from the production well bore and thus prevents proppant from flowing back from the fracture into the production well bore during fluid extraction. 11. The method of claim 4, further comprising screening and gravel packing inside the casing. 12. The method of claim 3, wherein the casing comprises two initiation sections with two directions of dilation and first and second weakening lines, wherein said first and second weakening lines are orthogonal. 13. The method of claim 3, wherein the casing comprises three initiation sections with three directions of dilation. 14. The method of claim 13, wherein each hydraulic fracture creates individual opposing wings, and wherein the casing enables controlling the rate of fracture fluid injection into each individual opposing wing of the initiated and propagating hydraulic fractures thereby controlling the geometry of the hydraulic fractures. 15. The method of claim 13, wherein the casing is two-thirds of the height of the completed interval to be hydraulically fractured. 16. The method of claim 13, wherein the casing is one-half of the height of the completed interval to be hydraulically fractured. 17. The method of claim 13, wherein the casing is one-third of the height of the completed interval to be hydraulically fractured. 18. The method of claim 13, wherein the initiation sections remain separated after dilation of the casing by the fracture fluid to provide hydraulic connection of the fracture with the well bore following completion of hydraulic fracturing. 19. The method of claim 13, wherein the fracture fluid comprises a proppant and the initiation sections each contain well screen sections separating the proppant in the hydraulic fracture from the production well bore and thus preventing proppant from flowing back from the fracture into the production well bore during fluid extraction. 20. The method of claim 13, wherein the method further comprises re-fracturing of each previously injected fracture. 21. The method of claim 13, further comprising screening and gravel packing inside the casing. 22. The method of claim 3, wherein the casing comprises four initiation sections with four directions of dilation, with first, second, third, and fourth weakening lines, wherein the first and second weakening lines being orthogonal to each other and the third and fourth weakening lines being orthogonal to each other. 23. The method of claim 22, wherein each hydraulic fracture creates individual opposing wings, and wherein the casing enables controlling the rate of fracture fluid injection into each individual opposing wing of the hydraulic fractures thereby controlling the geometry of the hydraulic fractures. 24. The method of claim 22, wherein the casing is two-thirds of the height of the completed interval to be hydraulically fractured. 25. The method of claim 22, wherein the casing is one-half of the height of the completed interval to be hydraulically fractured. 26. The method of claim 22, wherein the casing is one-third of the height of the completed interval to be hydraulically fractured. 27. The method of claim 22, wherein the initiation sections remain separated after dilation of the casing by the fracture fluid to provide hydraulic connection of the fracture with the well bore following completion of hydraulic fracturing. 28. The method of claim 22, wherein the fracture fluid comprises a proppant and the initiation sections each contain well screen sections separating the proppant in the hydraulic fracture from the production well bore and thus preventing proppant from flowing back from the fracture into the production well bore during fluid extraction. 29. The method of claim 22, wherein the method further comprises re-fracturing of each previously injected fracture. 30. The method of claim 22, further comprising screening and gravel packing inside the casing. 31. The method of claim 2, wherein a mandrel splits the casing and dilates the casing, the grout annulus and the formation and the hydraulic fracture fluid initiates the fracture in the formation at the weakening line. 32. The method of claim 2, wherein the initiation sections remain separated after dilation of the casing by the fracture fluid to provide hydraulic connection of the fracture with the well bore following completion of hydraulic fracturing. 33. The method of claim 2, wherein the fracture fluid comprises a proppant and the initiation sections each contain well screen sections separating the proppant in the hydraulic fracture from the production well bore and thus preventing proppant from flowing back from the fracture into the production well bore during fluid extraction. 34. The method of claim 1, wherein the fracture fluid is a water based fracturing gel. 35. The method of claim 1, wherein the fracture fluid is an oil based fracturing gel. 36. The method of claim 1, wherein the fracture fluid comprises a proppant. 37. The method of claim 36, wherein the fracture fluid comprises a proppant which has a size ranging from #4 to #100 U.S. mesh, and the proppant is selected from a group consisting of sand, resin-coated sand, ceramic beads, synthetic organic beads, glass microspheres, resin coated proppant and sintered minerals. 38. The method of claim 1, wherein the fracture fluid comprises a proppant, and the fracture fluid is able to carry the proppant of the fracture fluid at low flow velocities. 39. The method of claim 1, wherein the fracture fluid comprises a proppant and a proppant flowback-retention agent. 40. The method of claim 39, wherein the fracture fluid comprises a proppant flowback-retention agent, which is selected from a group consisting of natural organic fibers, synthetic organic fibers, glass fibers, carbon fibers, ceramic fibers, inorganic fibers, and metal fibers. 41. The method of claim 1, wherein the fracture fluid is clean breaking with minimal residue. 42. The method of claim 1, wherein the fracture fluid has a low friction coefficient. 43. The method of claim 1, wherein the fracture fluid pumping rate and the fracturing fluid viscosity are maintained during fracture propagation to ensure that Re is less than 250 at the fracture tip and the fracture fluid viscosity is maintained to be greater than 100 centipoise at the fracture tip. 44. The method of claim 1, wherein the fracture fluid injection rate, pressure and proppant loading is selected so as to promote a screening out of the fracture at the tip to create a wide fracture. 45. The method of claim 1, wherein the casing enables controlling the rate of fracture fluid injection into each individual opposing wing of the initiated and propagating hydraulic fracture thereby controlling the geometry of the hydraulic fracture. 46. The method of claim 1, wherein the method further comprises re-fracturing of each previously injected fracture. 47. The method of claim 1, wherein the casing is two-thirds of the height of the completed interval to be hydraulically fractured. 48. The method of claim 1, wherein the casing is one-half of the height of the completed interval to be hydraulically fractured. 49. The method of claim 1, wherein the casing is one-third of the height of the completed interval to be hydraulically fractured. 50. The method of claim 1, further comprising screening and gravel packing inside the casing. 51. The method of claim 1, wherein the dilation of the formation is achieved by first cuffing a vertical slot in the formation at the selected azimuth for the initiated fracture, injecting a fracture fluid into the slot with a sufficient fracturing pressure to dilate the formation in a preferential direction and thereby initiate a vertical fracture at an azimuth orthogonal to the direction of dilation; controlling the flow rate of the fracture fluid and its viscosity so that Re is less than 100 at the fracture initiation and less than 250 during fracture propagation and the fracture fluid viscosity is greater than 100 centipoise at the fracture tip. 52. A well in a formation of unconsolidated and weakly cemented sediments, comprising a bore hole in the formation to a predetermined depth; an injection casing in the bore hole at the predetermined depth; a source for delivering a fracture fluid into the injection casing with sufficient fracturing pressure to dilate the formation and initiate a vertical fracture with a fracture tip at an azimuth orthogonal to the direction of dilation, wherein the injection casing further comprises: a. multiple initiation sections separated by a weakening line, and b. multiple passages within the initiation sections and communicating across the weakening line for the introduction of the fracture fluid to dilate the formation in a preferential direction and thereby initiate the vertical fracture at the azimuth orthogonal to the direction of dilation and to control the propagation rate of each individual opposing wing of the hydraulic fracture; and wherein said source delivers the fracture fluid at a flow rate with an Re of less than 100 at the fracture initiation and less than 250 during fracture propagation and wherein the fracture fluid has a viscosity greater than 100 centipoise at the fracture tip. 53. The well of claim 52, wherein the fracture fluid is a water based fracturing gel. 54. The well of claim 52, wherein the fracture fluid is a oil based fracturing gel. 55. The well of claim 52, wherein the fracture fluid comprises a proppant. 56. The well of claim 52, wherein the fracture fluid comprises a proppant, and the fracture fluid is able to carry the proppant of the fracture fluid at low flow velocities. 57. The well of claim 56, wherein the fracture fluid comprises a proppant which has a size ranging from #4 to #100 U.S. mesh, and the proppant is selected from a group consisting of sand, resin-coated sand, ceramic beads, synthetic organic beads, glass microspheres, resin coated proppant and sintered minerals. 58. The well of claim 52, wherein the fracture fluid comprises a proppant and a proppant flowback-retention agent. 59. The well of claim 58, wherein the fracture fluid comprises a proppant flowback-retention agent, which is selected from a group consisting of natural organic fibers, synthetic organic fibers, glass fibers, carbon fibers, ceramic fibers, inorganic fibers, and metal fibers. 60. The well of claim 52, wherein the fracture fluid is clean breaking with minimal residue. 61. The well of claim 52, wherein the fracture fluid has a low friction coefficient. 62. The well of claim 52, wherein the fracture fluid injection rate, pressure, and proppant loading is selected so as to promote a screening out of the fracture at the tip to create a wide fracture. 63. The well of claim 52, wherein the initiation sections remain separated after dilation of the casing by the fracture fluid to provide hydraulic connection of the fracture with the well bore following completion of hydraulic fracturing. 64. The well of claim 52, wherein the fracture fluid comprises a proppant and the initiation sections each contain well screen sections separating the proppant in the hydraulic fracture from the production well bore and thus preventing proppant from flowing back from the fracture into the production well bore during fluid extraction. 65. The well of claim 52, wherein the method further comprises re-fracturing of each previously injected fracture. 66. The well of claim 52, wherein the casing is two-thirds of the height of the completed interval to be hydraulically fractured. 67. The well of claim 52, wherein the casing is one-half of the height of the completed interval to be hydraulically fractured. 68. The well of claim 52, wherein the casing is one-third of the height of the completed interval to be hydraulically fractured. 69. The well of claim 52, wherein a screen and gravel pack is completed inside of the casing. 70. A well in a formation of unconsolidated and weakly cemented sediments, comprising: a bore hole in the formation to a predetermined depth; an injection casing in the bore hole at the predetermined depth, the injection casing comprising multiple initiation sections separated by a weakening line having opposing wings, and passages within the initiation sections communicate a fracture fluid to each opposing wing of a selected weakening line, wherein each weakening line corresponds to one of a plurality of fracture planes; and a source for delivering the fracture fluid with sufficient pressure to dilate the formation, and initiate a fracture with a fracture tip in the formation along the desired fracture plane, and controlling the flow rate of the fracture fluid and its viscosity so that Re is less than 100 at the fracture initiation and less than 250 during fracture propagation and the fracture fluid viscosity is greater than 100 centipoise at the fracture tip. 71. A well in a formation of unconsolidated and weakly cemented sediments, comprising: a bore hole in the formation to a predetermined depth; an injection casing in the bore hole at the predetermined depth, the injection casing comprising multiple initiation sections separated by a weakening line, each weakening line having opposing wings, and passages within the initiation sections communicate a fracture fluid to each opposing wing of a selected opposed pair of weakening lines, wherein each opposed pair of weakening lines corresponds to one of a plurality of desired fracture planes; and a source for delivering the fracture fluid with sufficient pressure to dilate the formation, and initiate a fracture with a fracture tip in the formation along the desired fracture plane, and controlling the flow rate of the fracture fluid and its viscosity so that Re is less than 100 at the fracture initiation and less than 250 during fracture propagation and the fracture fluid viscosity is greater than 100 centipoise at the fracture tip.
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