Claims
- 1. A method for evaluating a formation characteristic in a well having a wellbore for intersecting a subsurface formation and being drilled from a wellbore surface with a drill bit carried at the end of a drill string, comprising:
establishing a measuring system having measuring instruments for measuring a fluid flowing into and out of said wellbore, forming a closed fluid flow system extending from said wellbore surface through said drill string and returning through an annulus between said wellbore and said drill string back to said wellbore surface whereby fluids injected into said drill string at said wellbore surface travel into and out of said wellbore through a confined flow passage defined in part by said drill string and annulus, measuring the flow of the fluid injected through the drill string into said closed fluid flow system with said measuring instruments, measuring the flow of the fluid returning through said annulus from said closed fluid flow system with said measuring instruments, making a calibration comparison of the measured flow of the fluid injected into said closed fluid flow system with the measured flow of fluid returning from said closed fluid flow system, calibrating said measuring system as a function of the calibration comparison to form a calibrated measuring system, measuring, with said calibrated measuring system, the fluid injected into said drill string from the wellbore surface, measuring, with said calibrated measuring system, the fluid returning to the wellbore surface from said annulus, establishing, at a first subsurface wellbore location, a first formation parameter value associated with said formation, and correlating the calibration measurements of fluid with said first formation parameter value for determining a characteristic of said formation at said first subsurface wellbore location.
- 2. A method as defined in claim 1 wherein a rate of fluid flow is measured by said calibrated measuring system.
- 3. A method as defined in claim 1 wherein a temperature and pressure value are established at said first subsurface wellbore location.
- 4. A method as defined in claim 1 wherein multiple first formation parameter values established at different subsurface wellbore locations are correlated with associated calibrated surface injection fluid measurements and surface return fluid measurements to determine a range of the formation characteristics at different locations traversed by the wellbore.
- 5. A method as defined in claim 1 wherein said characteristic of said formation comprises permeability of said formation.
- 6. A method as defined in claim 1 wherein said first formation parameter value is established using a data resource.
- 7. A method as defined in claim 1 wherein said first formation parameter value is established using a pressure or temperature transducer located at said first subsurface wellbore location.
- 8. A method as defined in claim 1 wherein said first formation parameter value is measured and recorded in a logging instrument carried by said drill string in said wellbore.
- 9. A method as defined in claim 1 wherein said measuring system includes a quantitative analysis instrument to measure flow rate of fluids returning to said wellbore surface through said annulus.
- 10. A method as defined in claim 1 wherein said measuring system includes an ultrasonic gas measurement instrument for measuring a quantity of gas in a fluid returning to said wellbore surface through said annulus.
- 11. A method as defined in claim 1 wherein said measuring system employs a qualitative analysis instrument for measuring a composition of fluids returning to said wellbore surface through said annulus.
- 12. A method as defined in claim 11 wherein said qualitative analysis instrument comprises a chromatograph.
- 13. A method as defined in claim 1 further comprising adding a tracer to fluid injected into the drill string at the wellbore surface to assist in determining a fluid circulation rate through said closed fluid flow system.
- 14. A method as defined in claim 13 wherein said tracer comprises a neon gas.
- 15. A method as defined in claim 1 wherein said wellbore is drilled into said formation in overbalanced condition wherein the pressure in said formation is less than the pressure in a bottom of said wellbore.
- 16. A method as defined in claim 1 wherein said wellbore is drilled into said formation in underbalanced condition wherein the pressure in said formation is greater than the pressure in a bottom of said wellbore.
- 17. A method as defined in claim 6 wherein said data resource comprises information from previously drilled wellbores into a same or similar formation.
- 18. A method as defined in claim 1 wherein measurements from said calibrated measuring system are used to evaluate rate of fluid flow from said formation.
- 19. A method as defined in claim 1 wherein said calibrated measuring system transmits data representing measurements of temperature and pressure to the wellbore surface.
- 20. A method as defined in claim 1 wherein said well is constructed as a function of a determined characteristic of said formation.
- 21. A method as defined in claim 1 wherein a material balance determination is made to relate composition and volume of fluid injected into the well through the drill string with composition and volume of fluid returning to the wellbore surface through the annulus.
- 22. A method as defined in claim 1 wherein said first formation parameter value is established using a fluid flow measuring instrument carried by said drill string in said wellbore.
- 23. A method as defined in claim 22 wherein said fluid flow measuring instrument comprises one or more of an acoustic, electromagnetic or capacitive transducer.
- 24. A method as defined in claim 22 wherein said fluid flow measuring instrument comprises a drill string carried instrument segment having multiple transducers for measuring variable parameters related to fluid flow through said wellbore.
- 25. A method as defined in claim 22 wherein said fluid flow measuring instrument comprises a drill string carried instrument segment having a fluid receiving recess defining a measurement containment area and having a measuring transducer for measuring a parameter of fluid contained in said measurement containment area.
- 26. A method as defined in claim 25 wherein said fluid flow measuring instrument is provided with multiple transducers for measuring a variable parameter related to fluid flow through said wellbore.
- 27. A method as defined in claim 26 wherein said multiple transducers include two or more transducers taken from a group consisting of acoustic, electromagnetic and capacitive transducers.
- 28. A method as defined in claim 22 wherein said first formation parameter value is established as said fluid flow measuring instrument is being rotated in said wellbore.
- 29. A method as defined in claim 22 wherein said fluid flow measuring instrument is carried by a stabilizing sub in stabilizing relationship with the drill bit.
- 30. A method as defined in claim 22 wherein said wellbore is drilled into said formation in underbalanced condition wherein the pressure in said formation is greater than the pressure in a bottom of said wellbore.
- 31. A method as defined in claim 22 wherein measurements from said fluid flow measuring instrument are compared with injection and return measurements of fluid flowing into and out of said wellbore.
- 32. A method as defined in claim 27 wherein measurements from said fluid flow measuring instrument are compared with injection and return measurements of fluid flowing into and out of said wellbore.
- 33. A method as defined in claim 32 wherein a material balance determination is made to relate composition and volume of fluid injected into the wellbore through the drill string with composition and volume of the fluid returning to the well surface through the annulus.
- 34. A method as defined in claim 32 wherein said measuring system measures variable parameters within said wellbore to assist in evaluating permeability of said formation.
- 35. A method as defined in claim 32 wherein said wellbore is constructed as a function of a determined characteristic of said formation.
- 36. A method as defined in claim 1 wherein one or more of a bottomhole temperature and a bottomhole pressure are used to determine the density or viscosity of fluid flowing from said formation into the wellbore.
- 37. A method as defined in claim 1 wherein an initial reservoir pressure of the formation is determined by terminating flow of fluids from said wellbore to allow the fluid pressure of fluids in said wellbore to rise to a value corresponding to the pressure of fluids in the formation.
- 38. A method as defined in claim 1 wherein a series of flows at different differential pressures between said wellbore and said formation are employed to extrapolate to an initial reservoir pressure of said formation.
- 39. A method as defined in claim 38 wherein an effective permeability for said formation is calculated using one or more of determined reservoir pressures and determined reservoir temperatures.
- 40. A method as defined in claim 39 wherein parameter measurements made in said wellbore are transmitted to the wellbore surface or are recorded in a subsurface recording instrument.
- 41. A method as defined in claim 1 wherein said measuring system is calibrated in a closed fluid flow system before said wellbore is extended into a productive reservoir formation.
- 42. A method as defined in claim 41 further comprising circulating a known quantity and density of fluid into said drill pipe and out of said annulus and calibrating measurement transducers in said system whereby a material balance situation exists in fluid circulating in said closed fluid flow system.
- 43. A method as defined in claim 42 wherein the following parameters are measured at a minimum of two different circulating fluid pressures in said drill string and annulus:
injection pressures, temperatures and flow rates; wellbore bottom annulus pressures and temperatures; annulus returned pressures, temperatures and flow rates; and hydrocarbon percentages measured over a period exceeding 1.1 wellbore circulation volumes.
- 44. A method as defined in claim 1 further comprising monitoring a circulation time for fluid to circulate from said wellbore surface through said drill string and return to said wellbore surface through said annulus.
- 45. A method as defined in claim 44 wherein said circulation time is monitored by utilizing a tracer in the fluid injected into said drill string at said wellbore surface and determining the time required for the tracer to return to the wellbore surface through the annulus.
- 46. A method as defined in claim 45 wherein said tracer comprises a carbide, an inert substance or a short half-life radioactive material.
- 47. A method as defined in claim 1 wherein a top of a reservoir in said formation is identified by a change in one or more of a wellbore bottomhole pressure, a wellbore bottomhole temperature, a hydrocarbon measurement in the annular fluid or a fluid flow rate through the drill pipe or annulus.
- 48. A method as defined in claim 47 wherein reservoir flow from a reservoir intersected by said wellbore is analyzed by relating varying annular back pressures at said wellbore surface with flow rates in said annulus.
- 49. A method as defined in claim 1 wherein said first formation parameter value is determined from computer modeling.
- 50. A method as defined in claim 4 wherein said first formation parameter values are established using computer modeling.
- 51. A method as defined in claim 21 further including separating fluids flowing from said annulus at said wellbore surface into constituent components.
- 52. A method as defined in claim 1 further comprising determining the occurrence of a wellbore bottomhole pressure increasing to signal the occurrence of a kick during well construction.
- 53. A downhole tool for connection with a drill bit in a drill string for measuring a variable parameter in a wellbore while said wellbore is being constructed, comprising:
a longitudinally extending tool body having an internal passage for conveying fluid between first and second longitudinal ends of said tool body; one or more longitudinally extending fluid recesses in said tool body external to said internal passage for receiving fluid to be measured, and energy transducers carried by said tool body for evaluating a fluid contained in said fluid recesses.
- 54. A downhole tool as defined in claim 53 wherein said energy transducers respond to the flow rate of fluid flowing through said channel.
- 55. A downhole tool as defined in claim 53 wherein said energy transducers comprise one or more of acoustic transducers and electromagnetic induction transducers and electrical capacitance transducers.
- 56. A downhole tool as defined in claim 53 wherein said energy transducers comprise acoustic transducers and electromagnetic induction transducers.
- 57. A downhole tool as defined in claim 53 wherein said energy transducers comprise acoustic transducers and electromagnetic induction transducers and electrical capacitance transducers.
- 58. A downhole tool as defined in claim 53, wherein said tool body includes laterally and longitudinally extending, circumferentially spaced blades extending laterally away from said internal passage wherein at least one of said fluid recesses comprises a channel formed between adjacent blades and wherein said energy transducers comprise an energy transmitting transducer on a first blade and an energy receiving transducer on an adjacent second blade wherein energy transmission from said transmitting transducer travels along a path through a fluid in said channel to said receiving transducer to evaluate of said fluid traversed by said energy transmission while traveling along said path.
- 59. A downhole tool as defined in claim 58 wherein,
one or more energy transmitting transducers are mounted on said first blade and multiple energy receiving transducers are mounted on said second blade, multiple energy transmissions between said one or more transmitting transducers and said multiple receiving transducers are responsive to a gas bubble entrained in a liquid comprising the fluid in said channel, and energy transmissions received by said energy receiving transducers have characteristics functionally related to travel along paths from said one or more transmitting transducers to said receiving transducers for determining a rate of axial flow of said gas bubble through said channel.
- 60. A downhole tool as defined in claim 59 wherein said one or more energy transmitting transducers and multiple energy receiving transducers comprise electromagnetic transducers.
- 61. A downhole tool as defined in claim 59 wherein said one or more energy transmitting transducers and multiple energy receiving transducers comprise acoustic transducers.
- 62. A downhole tool as defined in claim 59 wherein said one or more energy transmitting transducers and multiple energy receiving transducers comprise electromagnetic transducers and acoustic transducers.
- 63. A downhole tool as defined in claim 62 further comprising multiple electrical capacitance transducers.
- 64. A downhole tool as defined in claim 59 wherein said one or more energy transmitting transducers and said multiple energy receiving transducers are spaced longitudinally along said first and second blades.
- 65. A downhole tool as defined in claim 53 further comprising one of a recording and a transmitting instrument for recording downhole in said wellbore or transmitting to a surface of said wellbore data derived by said energy transducers.
- 66. A downhole tool as defined in claim 53 further comprising electromagnetic transducers for measuring the conductivity of a fluid contained in said fluid receiving recesses.
- 67. A downhole tool as defined in claim 53 further comprising electrical capacitance transducers for determining an electrical capacitive characteristic between said capacitive transducers and the fluid contained in the fluid receiving recesses.
- 68. A downhole tool as defined in claim 53 wherein said energy transducers are situated to evaluate said fluid contained in said one or more fluid recesses while said downhole tool is rotated within said wellbore.
- 69. A downhole tool as defined in claim 58 wherein said energy transducers obtain data to evaluate said fluid contained in said channel while said downhole tool is rotated in said wellbore.
- 70. A downhole tool as defined in claim 58 wherein said tool body is a stabilizer and said blades extend helically.
- 71. A downhole tool as defined in claim 53 wherein said first longitudinal end of said tool body connects with a drill string extending to a surface of said wellbore and said second longitudinal end of said tool body connects with a drill bit.
- 72. A system having a bottomhole measuring instrument secured to a drill string and bit for detecting a kick in a wellbore of a well being drilled into a subsurface formation, comprising:
a bottomhole measuring instrument having an axially extending tool body and a central, axially developed passage for conveying fluid between first and second axial ends of said tool body, radially and axially extending, circumferentially spaced blades carried on an external surface of said tool body, fluid receiving recesses defined between said circumferentially spaced blades for receiving fluid located in an area intermediate said external surface of said tool body and the wellbore, energy transducers carried by said blades for evaluating fluid contained in said fluid receiving recesses, and a kick signaling system responsive to said transducer to evaluate said fluid contained in said fluid receiving recesses for signaling the occurrence of a kick in said well.
- 73. A system as defined in claim 72 wherein said energy transducers are responsive to at least one of the flow rate and composition of fluid flowing through said fluid receiving recesses.
- 74. A system as defined in claim 72 wherein said energy transducers comprise acoustic transducers or electromagnetic transducers or electrical capacitance transducers.
- 75. A system as defined in claim 72 wherein said energy transducers comprise an energy transmitting transducer on a first blade and one or more energy receiving transducers on an adjacent second blade whereby energy transmission from said energy transmitting transducer travels along one or more paths through a fluid receiving recess to said energy receiving transducer to evaluate a fluid traversed by said energy transmission while traveling along said one or more paths.
- 76. A system as defined in claim 75 wherein,
one or more energy transmitting transducers are mounted on said first blade and multiple energy receiving transducers are mounted on said second blade, multiple energy transmissions between said one or more transmitting transducers and said multiple receiving transducers are responsive to a gas bubble entrained in a liquid comprising the fluid in one of said fluid receiving recesses, and energy transmissions received by said energy receiving transducers have characteristics functionally related to travel of energy transmissions along said paths from said one or more transmitting transducers to said receiving transducers for use in a time based calculation to determine a rate of axial flow of said gas bubble through one of said fluid receiving recesses.
- 77. A system as defined in claim 76 comprising a kick indication sign to signal a kick when a fluid flow from said formation into said wellbore is detected by said energy transducers.
- 78. A method for evaluating a subsurface formation traversed by a wellbore constructed from a well surface with a drill bit carried at the end of a drill string, comprising:
establishing a measuring system for measuring a fluid injection rate of fluid injected into the drill string from the well surface, taking a first measurement of the rate of fluid flow between said wellbore and said formation with a subsurface flow measurement tool carried on the drill string, determining a first location within said wellbore where said first rate of fluid flow is measured, determining the fluid injection rate while said first measurement is taken, deepening said borehole with said drill bit, taking a second measurement of the rate of fluid flow between said wellbore and said formation with said subsurface flow measurement tool, determining a second location within said wellbore where said second rate of fluid flow is measured, determining the fluid injection rate while said second measurement is taken, and correlating the fluid injection rates into the drill string and the locations within said wellbore where said measurements are taken to determine a permeability change between said first and second locations.
- 79. A method as defined in claim 78 further comprising altering construction of said wellbore as a function of said permeability change.
- 80. A method as defined in claim 78 further comprising performing multiple correlations at multiple locations within said wellbore to produce a profile relating permeability and wellbore depths along a substantial length of said formation.
- 81. A method as defined in claim 78 further comprising measuring fluids returning to said well surface from said wellbore.
- 82. A method as defined in claim 78 wherein pressure in said formation is greater than pressure in said wellbore whereby fluid flows from said formation into said wellbore.
- 83. A method as defined in claim 78 wherein pressure in said formation is less than pressure in said wellbore whereby fluid flows from said wellbore into said formation.
- 84. A method as defined in claim 80 further comprising measuring fluids returning to said well surface from said wellbore.
- 85. A method as defined in claim 84 further comprising altering construction of said wellbore as a function of said permeability change.
- 86. A method as defined in claim 78 further comprising:
conveying said fluid through an internal passage between first and second longitudinal ends of a tool body; providing one or more longitudinally extending fluid recesses in said tool body external to said internal passage for receiving fluid to be measured, and carrying energy transducers by said tool body for evaluating a fluid contained in said fluid recesses.
- 87. A method as defined in claim 86 further comprising positioning said energy transducers to respond to the flow rate of fluid flowing through said channel.
- 88. A method as defined in claim 86 further comprising positioning one or more of acoustic transducers and electromagnetic induction transducers and electrical capacitance transducers on said tool body.
- 89. A method as defined in claim 86, further providing laterally and longitudinally extending, circumferentially spaced blades extending laterally away from said internal passage wherein at least one of said fluid recesses comprises a channel formed between adjacent blades.
- 90. A method as defined in claim 86, further comprising placing an energy transmitting transducer on one blade and an energy receiving transducer on an adjacent blade wherein energy transmission from said transmitting transducer travels along a path through a fluid in said channel to said receiving transducer to permit evaluation of said fluid traversed by said energy transmission while traveling along said path.
- 91. A method as defined in claim 86 further comprising,
mounting, one or more energy transmitting transducers on said first blade and multiple energy receiving transducers on said second blade, sensing a gas bubble entrained in a liquid comprising a fluid in said channel with multiple energy transmissions between said one or more transmitting transducers and said multiple receiving transducers, and functionally relating energy transmissions along paths from said one or more transmitting transducers to said receiving transducers for determining a rate of axial flow of said gas bubble through said channel.
REFERENCE TO RELATED PATENT APPLICATIONS
[0001] This application claims priority from U.S. provisional application serial No. 60/233,847 filed Sep. 20, 2000.
Provisional Applications (1)
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Number |
Date |
Country |
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60233847 |
Sep 2000 |
US |