US20050139393A1

US20050139393A1 - Turbine generator system and method

Info

Publication number: US20050139393A1
Application number: US11/024,285
Authority: US
Inventors: William Maurer; William McDonald
Original assignee: Noble Drilling Corp
Current assignee: Noble Drilling Corp; Noble Drilling Services LLC
Priority date: 2003-12-29
Filing date: 2004-12-28
Publication date: 2005-06-30
Also published as: WO2005066452A1; CA2552227C; CA2552227A1

Abstract

In one embodiment, a wellbore power generation method includes causing a fluid to flow through a downhole turbine, and causing the turbine to rotate a generator. At least one of a turbine configuration and a flow rate of the fluid is selected to cause the downhole turbine to operate near its runaway speed, such that changes in load applied to the generator do not substantially affect a rotation rate of the downhole turbine.

Description

RELATED APPLICATIONS

Priority is claimed from U.S. Provisional Application Ser. No. 60/532,931, entitled “Downhole Turbine Generator Apparatus,” filed provisionally on Dec. 29, 2003.

TECHNICAL FIELD OF THE INVENTION

This invention relates generally to the field of power generation and, more particularly, to a downhole turbine generator system and method.

BACKGROUND OF THE INVENTION

Downhole wellbore drilling tools include instrumentation, such as “measurement while drilling” (MWD) instruments, which use flow of drilling mud to operate an electrical generator and/or hydraulic pump. The electrical generator and/or hydraulic pump provides power to operate various devices within such instruments, for example, to power electronic circuitry and/or to operate various steering devices that are hydraulically actuated.
It is known in the art to use a turbine to convert drilling mud flow into rotational energy to drive the electrical generator and/or hydraulic pump. A turbine includes a plurality of circumferentially spaced apart “blades” having physical characteristics selected to provide a particular rotational speed and torque (the product of which is the power) output to drive a electrical generator and/or hydraulic pump for a selected flow rate of drilling mud therethrough.
For most turbines, turbine blades deliver maximum power output when operated at about half of their “runaway” speed (rotational speed of the turbine with substantially zero load). A graph of the power output with respect to turbine rotation rate of a typical fluid driven turbine has a characteristic trajectory. The trajectory begins at zero power output at zero speed, rises to a power peak at a determinable rotation speed, and again returns to zero power output at the runaway speed. Near the peak power output, even small changes in the load applied to the turbine can result in large changes in the rotational speed of the turbine at a constant mud flow rate. When driving a device such as an electric generator, for example, such small changes in load may occur in response to meeting the demands of downhole electrically powered equipment, such as the switching of electronics or the firing of solenoid-operated valves, and thus can cause significant changes in the turbine rotary speed. Such changes in the rotary speed may result in the turbine not delivering adequate power to the downhole equipment under increased load conditions.
The rotary speed of a turbine varies approximately linearly with the mud flow rate through the turbine. As a result, turbine-driven power generating systems used in downhole equipment must use a wide variety of blade characteristics (e.g., blade angle, blade flow area, blade pitch and curvature, etc.) to allow use of the turbine generator system in a number of different expected drilling mud flow rates. Generally, the blade characteristics in the turbine must be selected to match the expected mud flow rates. When drillers change the mud flow rate by more than about 25%, it is usually necessary to change the turbine blade configuration to match, otherwise the turbine may not deliver adequate power to the electrical and/or hydraulic generator.
Changing the blade configuration can include, for example, adding additional “stages” (combination of turbine and stator sections) or changing the physical characteristics of the turbine in one or more such sections. Changing the blade configuration can be a time-consuming and expensive operation since the downhole tool must be pulled from the well to change any aspect of the turbine system. Further, manufacturing and maintaining additional turbine sets to enable use with varying expected mud flow rates can add to the overall capital cost of such systems.

SUMMARY OF THE INVENTION

In one embodiment, a wellbore power generation method includes causing a fluid to flow through a downhole turbine, and causing the turbine to rotate a generator. At least one of a turbine configuration and a flow rate of the fluid is selected to cause the downhole turbine to operate near its runaway speed, such that changes in load applied to the generator do not substantially affect a rotation rate of the downhole turbine.
Embodiments of the invention may provide a number of technical advantages. In one embodiment, operating a downhole turbine at or near its runaway speed causes an electric generator for a downhole drilling tool to be very stable and operate at relatively constant speed, which makes the electric generator easier to use. Such an operating method facilitates fewer turbine blade designs, which reduces the need to inventory a large number of turbine blade designs and eliminates the need to disassemble the tool and change the blade designs for different well applications.
Other technical advantages are readily apparent to one skilled in the art from the following figures, descriptions, and claims.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 is a cross-sectional elevation view illustrating a turbine generator used in drilling a wellbore in accordance with one embodiment of the present invention;
FIG. 2 is a graph illustrating the operating range of prior art turbines; and
FIG. 3 is a graph illustrating an operating range of a turbine in accordance with one embodiment of the present invention.

DETAILED DESCRIPTION

FIG. 1 is cross-sectional elevation view illustrating a turbine generator 100 used in drilling a wellbore 102 in accordance with one embodiment of the present invention. Although FIG. 1 illustrates turbine generator 100 being used in the drilling of wellbore 102, the present invention contemplates other applications for turbine generator 100, such as the production of wellbore fluids and fluid flow in pipelines, such as oil and gas gathering lines and major pipelines, or other suitable conduits.
In the illustrated embodiment in FIG. 1, turbine generator 100 is associated with a suitable drilling tool (not explicitly illustrated) in order to drill wellbore 102. For example, the drilling tool may be a measurement while drilling (“MWD”) tool, logging while drilling (“LWD”) tool, rotary steerable directional drilling tool, or other suitable tools. Turbine generator 100 may be used to provide electrical and/or hydraulic power to any suitable system, equipment, instrument, or device, such as simple electronic sensors, data acquisition and control (“DAC”) systems, downhole hydraulic power generation systems, systems that switch hydraulic valves downhole, resistivity and nuclear magnetic residence (“NMR”) logging tools, Electromagnetic (“EM”)-type LWD tools, or other suitable MWD tools. In a pipeline application, turbine generator 100 could be used to “trickle charge” batteries used for powering monitoring stations on pipelines or for powering cathodic protection devices in extremely harsh environments. The present invention contemplates turbine generator 100 delivering any suitable amount of power to any suitable system, equipment, instrument, or device.
The present invention also contemplates any suitable configuration for turbine generator 100. In the illustrated embodiment, turbine generator 100 includes a turbine 111 comprised of a turbine shaft 104 and a rotor blade assembly 106, and a stator blade assembly 105 that are each disposed within a housing 103. Each of these components may have any suitable size and shape and may be formed from any suitable material known in the art for use in wellbore turbine power generation systems. Both stator blade assembly 105 and rotor blade assembly 106 may have any suitable blade design known in the art.
Turbine 111 is driven by a fluid 110 flowing through housing 103. Fluid 110 is circulated through housing 103 by a pump 108, which may be any suitable device operable to circulate fluid through housing 103. Fluid 110 may be any suitable fluid depending on the application. For example, in the illustrated embodiment, fluid 110 is a suitable drilling fluid, such as drilling mud. In other applications, fluid 110 may be a production fluid or other suitable fluid.
In downhole turbine power generation systems known in the art, as explained in the BACKGROUND section herein, turbine blades operate most efficiently and deliver maximum power output when operated at approximately half of their runaway speed for any selected flow rate. Consequently, turbine generating systems known in the art typically have turbine blade characteristics selected to provide peak power output at the expected flow rate of drilling mud through the turbine. At the peak power output value (about half runaway speed), however, small changes in power output of the turbine correspond to relatively large changes in the rotation speed of the turbine. Thus, small changes in power load on the generating device driven by the turbine, such as to meet variable demand of certain downhole equipment, for example, the switching of electronics or the firing of solenoid valves, may cause significant changes in the turbine rotary speed. This is illustrated in FIG. 2, which shows a graph 200 of power output with respect to rotation speed of typical turbine power generation systems.
As illustrated by graph 200, an operating range 202 (the shaded area under the curve) illustrates the operating range of prior art downhole turbines. As illustrated, operating range 202 is at or very near 50% of the runaway speed for the downhole turbine. Thus, small changes in the power output to meet the changes in demand of the downhole equipment may cause a significant change in the rotary speed of the downhole turbine, as shown by graph 200. As a result, the downhole turbine system may not deliver adequate power to the downhole equipment under some load conditions.
Therefore, in one embodiment of the invention, turbine 111 is caused to operate at or near its runaway speed by adjusting the flow of fluid 110 through housing 103. This is illustrated in FIG. 3, which shows a graph 300 of power versus speed of turbine 111 according to one embodiment of the invention. Operating the turbine at or near its runaway speed can be attained by selecting a turbine blade configuration for which the peak power output (at one half runaway speed) is much greater than the maximum expected load on the turbine.
In the embodiment illustrated in FIG. 3, an operating range 302 shows that turbine 111 is operated at a minimum of about 75% of its runaway speed. In other embodiments, downhole turbine 111 operates at a minimum of about 85% of its runaway speed. In a more particular embodiment of the invention, turbine 111 operates substantially at its runaway speed. Operating turbine 111 at or near its runaway speed prevents changes in power output from significantly varying the speed of turbine 111, which makes turbine 111 less vulnerable to short-duration “spike” loads that may occur during a drilling operation, such as activating solenoid valves or pulsing the stepper motor in a mud pulse LWD system. In addition, in some embodiments, turbine 111 may deliver much more power than is needed by the downhole equipment so turbine 111 may always deliver adequate power regardless of the flow rate of fluid 110 or the power requirement of the equipment.
Another important advantage of operating turbine 111 at or near its runaway speed is that it eliminates the need to have available a large number of different turbine blade configurations, as in previous downhole turbine systems. Most operators of such downhole turbine systems keep an inventory of somewhere between five to ten different turbine blade designs for the situation when the drilling fluid flow rate needs to be changed in respect of certain drilling conditions. Changing the blade configuration can be a time-consuming and expensive operation since the downhole tool must be pulled from the wellbore to change any part of the turbine.
In operation of one embodiment of the invention, a wellbore drilling method may include drilling wellbore 102 with a drilling tool having turbine 111 that is driven by drilling fluid 110 flowing at a first flow rate. Turbine 111 is caused to operate at its runaway speed during the drilling process. If an operator needs to overcome hole problems, such as inadequate rock cuttings removal from the hole or hole enlargements that require higher flow rates to lift the rock cuttings in the enlarged zones, the flow rate of fluid 110 needs to be increased. Therefore the flow rate of drilling fluid 110 may be changed to a second flow rate without removing the drilling tool from wellbore 102. In one embodiment, the second flow rate is different from the first flow rate by at least twenty-five percent.
Although embodiments of the invention and their advantages are described in detail, a person of ordinary skill in the art could make various alterations, additions, and omissions without departing from the spirit and scope of the present invention as defined by the appended claims.

Claims

1. A wellbore power generation method, comprising:

causing a fluid to flow through a downhole turbine;

causing the turbine to rotate a generator; and

wherein at least one of a turbine configuration and a flow rate of the fluid is selected to cause the downhole turbine to operate near its runaway speed, such that changes in load applied to the generator do not substantially affect a rotation rate of the downhole turbine.

2. The method of claim 1, wherein causing the downhole turbine to operate near its runaway speed comprises causing the downhole turbine to operate at a minimum of 75% of its runaway speed.

3. The method of claim 1, wherein causing the downhole turbine to operate near its runaway speed comprises causing the downhole turbine to operate at a minimum of 85% of its runaway speed.

4. The method of claim 1, wherein causing the downhole turbine to operate near its runaway speed comprises causing the downhole turbine to operate substantially at its runaway speed.

5. The method of claim 1, wherein the downhole turbine generator is associated with a drilling tool and the fluid is a drilling fluid.

6. The method of claim 5, wherein the drilling tool is selected from the group consisting of a MWD tool, a LWD tool, and a rotary steerable tool.

7. The method of claim 1, wherein the generator comprises an electric generator.

8. The method of claim 1, wherein the generator comprises a hydraulic pump.

9. The method of claim 1, wherein the downhole turbine generator is associated with a producing well and the fluid is a production fluid.

10. A wellbore power generation system, comprising:

a pump circulating a fluid through a downhole turbine to rotate a generator; and

11. The system of claim 10, wherein the fluid operates the downhole turbine at a minimum of 75% of its runaway speed.

12. The system of claim 10, wherein the fluid operates the downhole turbine at a minimum of 85% of its runaway speed.

13. The system of claim 10, wherein the fluid operates the downhole turbine substantially at its runaway speed.

14. The system of claim 10, further comprising a drilling tool associated with the downhole turbine generator and wherein the fluid is a drilling fluid.

15. The system of claim 14, wherein the drilling tool is selected from the group consisting of a MWD tool, a LWD tool, and a rotary steerable tool.

16. The method of claim 10, wherein the generator comprises an electric generator.

17. The method of claim 10, wherein the generator comprises a hydraulic pump.

18. The system of claim 10, further comprising a producing well associated with the downhole turbine generator and wherein the fluid is a production fluid.

19. A wellbore drilling method, comprising:

drilling a wellbore with a drilling tool, the drilling tool comprising a downhole turbine driven by a drilling fluid flowing at a first flow rate;

causing the downhole turbine to operate near its runaway speed; and then

changing the flow rate of the drilling fluid to a second flow rate without removing the drilling tool from the wellbore, the second flow rate being different from the first flow rate by at least twenty-five percent.

20. The method of claim 19, wherein causing the downhole turbine to operate near its runaway speed comprises causing the downhole turbine to operate at a minimum of 75% of its runaway speed.

21. The method of claim 19, wherein causing the downhole turbine to operate near its runaway speed comprises causing the downhole turbine to operate substantially at its runaway speed.

22. A power generation method, comprising:

causing a fluid to flow through a turbine disposed in a conduit; and

causing the turbine to rotate a generator; and

wherein at least one of a turbine configuration and a flow rate of the fluid is selected to cause the turbine to operate near its runaway speed, such that changes in load applied to the generator do not substantially affect a rotation rate of the turbine.

23. The method of claim 22, wherein causing the turbine to operate near its runaway speed comprises causing the turbine to operate at a minimum of 75% of its runaway speed.

24. The method of claim 22, wherein causing the turbine to operate near its runaway speed comprises causing the turbine to operate substantially at its runaway speed.