Datacoil™ Downhole Logging System

Abstract

A logging tool for use within a work string within a wellbore. The logging tool includes one or more sensors which detect operational conditions within the wellbore and a processing and storage means for recording data relating to these conditions.

Description

BACKGROUND OF THE INVENTION

1. Field of the Invention

The present invention generally relates to the design of a mechanical and electronic logging tool used in conjunction with coiled tubing and other work strings for downhole operations. In particular aspects, the invention relates to a logging tool used in conjunction with a jarring tool to permit beneficial adjustment of operational parameters of the jarring tool. The other aspects, the invention relates to a logging tool used in conjunction with a drilling assembly or a scale cleaning assembly to permit adjustment of operational parameters for the operation of those assemblies.

2. Description of the Related Art

A coiled tubing bottom hole assembly (BHA) is primarily made up of check valves, disconnects, flow nozzles, hydraulic jars, mud motors, etc. These tools are deployed to perform a number of service tasks such as milling, drilling, circulating, jarring to remove stuck equipment, placement of devices, multi-lateral entry and high deviation/horizontal wellbore intervention to name but a few applications.

The standard design for a BHA assembly or part thereof requires a constant outside diameter relative to that of the entire BHA and a common internal diameter for passage of fluid/gas and a ball drop release mechanism in the event the BHA is stuck in the wellbore and needs to be shear released to recover the coiled tubing or drill string. The assembly includes threaded connections at the top and bottom ends and can accommodate both internal and external fishing necks for retrieval.

The deployment of BHAs via coiled tubing and drilling industry has relied heavily on modeling software and calculations to determine many mechanical factors of the BHA including friction, weight on bit, pressure differentials, inclination, impact forces, torque, etc, since the sensor technology to record these parameters, in many cases, has not been available.

For decades, the oil and gas industry has used these modeling systems and calculus to determine if the BHA is acting and operating in accordance with these to models, however without actual BHA data only the surface information is available to determine if the BHA is responding to surface control inputs. All too often the surface models and input from surface controls such as applying weight on bit, increasing or decreasing pump rates, changing pressures and altering tension or compression fail to optimize or result in a successful intervention for removing a stuck device milling out of bridge plugs or accurately determining multi lateral entry angle. In many cases, several different runs into the wellbore are needed to accomplish the task at hand.

In the instance of jarring operations, there are often a number of separate runs into the wellbore that need to be made before the jarring operation is successful, i.e., by the successful removal of a stuck device within the wellbore. Changes to the jarring arrangement must be made largely on the basis of trial and error until successful.

SUMMARY OF THE INVENTION

The present invention provides a system and method for providing bottom hole assembly data analysis associated with jarring and/or drilling operations. The systems and method of the present invention are particularly well suited for use with coiled tubing running arrangements, although may be used with running arrangements using standard drill pipe as well. In one aspect, logging systems in accordance with the present invention are designed to provide the end user with a compact through-tubing, flow-through assembly that is capable of monitoring and recording data relating to multiple BHA parameters simultaneously and record these events to memory for later analysis once the BHA has been retrieved. Thereafter, the recorded data can be downloaded or transferred to a surface-based computer to be analyzed and permit to operators to adjust a number of operating parameters, such as flow rate, pump pressure or tension on the coiled tubing. A logging tool constructed in accordance with the present invention embodies various sensor arrays that permit this analysis of a BHA and may include multiple data analyses, including a differential pressure analysis, temperature analysis, a weight-on-bit analysis, a jar output analysis, torque analysis.

A jarring arrangement is described in an embodiment which includes a logging tool that is incorporated into a coiled tubing work string having a jarring tool. The jarring tool is operated using fluid flow through the coiled tubing. The logging tool includes sensors that are operable to detect operating parameters such as flowbore pressure, temperature, strain and impact from the jarring tool. These operating parameters are detected by the sensors and stored on-board the logging tool in a processing and storage means. When the jarring arrangement is removed from the wellbore, the stored data is downloaded or transferred to a surface-based computer, displayed and thereafter analyzed to determine what changes in operating parameters could be made to the jarring arrangement to make it more effective.

A logging tool in accordance with the present invention is also useful in other work strings. An arrangement is described wherein an exemplary logging tool is used in a drilling string in order to detect and record operating parameters relating to the drilling BHA. Also, an arrangement is described wherein an exemplary logging tool is used with a scale clean-out operation.

BRIEF DESCRIPTION OF THE DRAWINGS

The advantages and other aspects of the invention will be readily appreciated to by those of skill in the art and better understood with further reference to the accompanying drawings in which like reference characters designate like or similar elements throughout the several figures of the drawings and wherein:

FIG. 1 is a side, cross-sectional view of an exemplary wellbore containing a coiled tubing running string with a jarring tool bottom hole assembly and an exemplary logging tool constructed in accordance with the present invention.

FIG. 2 is a side, cross-sectional view of an exemplary logging tool constructed in accordance with the present invention.

FIG. 3 is a schematic diagram showing exemplary steps performed in association with the exemplary logging tool shown in FIGS. 1 and 2.

FIG. 4 is a side, cross-sectional view of an exemplary wellbore containing a drilling string which incorporates an exemplary logging tool in accordance with the present invention.

FIG. 5 is a side, cross-sectional view of an exemplary wellbore containing a coiled tubing work string with a scale clean-out tool and an exemplary logging tool in accordance with the present invention.

DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENTS

FIG. 1 illustrates an exemplary wellbore 10 which has been drilled through the earth 12 down to a hydrocarbon-bearing formation 14 from the surface 16. Perforations 18, of a type known in the art, extend through the wellbore 10 and outwardly into the formation 14 to permit hydrocarbon production fluid to flow from the formation 14 to the interior of the wellbore 10. A device 15, such as a packer of a type known in the art, is shown stuck within the wellbore 10.

A coiled tubing injection unit 20, of a type known in the art, is located at the surface 16 and is depicted injecting a coiled tubing production string 22 into the wellbore 10. At the distal end of the coiled tubing string 22 is affixed a bottom hole assembly (BHA) 23. An annulus 25 is defined between the bottom hole assembly 23 and the wellbore 10. The bottom hole assembly 23 includes an impact jarring tool 24. The impact jar device 24 is a jarring device of a type known in the art for imparting a jar force to a tool (not shown) within the wellbore 10 in response to fluid flowed downwardly through the coiled tubing string 22. Suitable impact jars for use as the impact jarring tool 24 include the devices known generally in the industry as “vibratory hammers.” It is noted that, while a coiled tubing arrangement is depicted, the invention is not limited to use within a coiled tubing system. The invention may also be used with conventional production tubing strings, of a type known in the art, which are formed of interconnected tubing string sections.

The bottom hole assembly 23 also includes a logging tool 26, in accordance with the present invention, and a fishing tool 28 which extends below the logging tool 26. The fishing tool 28, as is known to those of skill in the art, is used to affix the BHA 23 to a tool (not shown) within the wellbore 10 to which it is desired to impart jarring impacts. The jarring operation in this example is used to remove the stuck tool 15, which it is desired to remove from the wellbore 10. Typically, the fishing tool 28 includes a plurality of collet fingers which selectively latch onto the stuck tool 15 and will be lowered in the direction of the arrow shown in FIG. 1 until the fishing tool 28 to engages the stuck tool 15.

An exemplary logging tool 26 is shown in greater detail in FIG. 2. As shown, the logging tool 26 includes a generally cylindrical tool body 30 having an upper axial end 32 and a lower axial end 34. The upper axial end 32 includes a box-type threaded connection 36, while the lower axial end 34 includes a pin-type threaded connection 38 by which the logging tool 26 can be interconnected with the fishing tool 28. The tool body 30 includes a central sensor mandrel 40 with machined pockets 41 to house sensors and circuit boards. There is a lower sub 42 affixed to the lower end of the mandrel and which includes the threaded connection 38. An axial flowbore 44 is defined along the length of the tool body 30 and which will be aligned with the central flow passage of the coiled tubing string 22 when the logging tool 26 is incorporated into the production string 22. A sensor isolation sleeve 46 radially surrounds the sensor mandrel 40. Annular fluid seals 48, of a type known in the art, are disposed between the sensor mandrel 40 and the sleeve 46 to assure fluid tightness.

The logging tool 26 includes programmable digital data processing means and data storage means. In the exemplary embodiment shown in FIG. 2, the processing and storage means are embodied within a mother board 50 and a daughter board 52, both of which are in the form of programmable printed circuit board assemblies that are disposed in an annular manner around or within the mandrel 40. Although two separate boards are depicted, there may be more or fewer than two on which the circuitry is located. The mother and daughter boards 50, 52 are preferably provided with on-board battery power supplies, as is known in the art. The processing means receives data from individual sensors and mathematically converts this data to appropriate engineering units, such as degrees Celsius, pounds per square inch, inclination angle and so forth. The converted data can be readily transmitted or downloaded to a surface-based computer for analysis. Numerical calibration factors for the mathematical conversion can be provided via assembly testing or by sensor manufacturer calibration data. The converted data is then labeled and time stamped by the data processing means and stored by the storage means in non-volatile random access memory for later transmission to the surface-based computer. Preferably, the processing and storage means can record large amounts of data at periodic, pre-programmed rates. Because the data is preferably stored with time/date information, data that is taken during critical job times can be selectively downloaded for analysis without requiring time for a complete data set transfer. Further, the surface-based computer can graphically display data for a total job time. Periodic points can be selected and displayed in greater detail.

A plurality of sensors is operably interconnected with the processing and storage means of the mother and daughter boards 50, 52. An annulus pressure sensor 54 is disposed within the mandrel 40 and is exposed to the annulus 25 of the wellbore 10. The annulus pressure sensor 54 is associated by electrical connection 56 to the daughter board 52. A flowbore pressure sensor 58 surrounds the mandrel 40. Pressure passages 60 extend through the mandrel 40 to permit fluid pressure from within the central flowbore 44 to be communicated to the flowbore pressure sensor 58. The flowbore pressure sensor 58 is operably associated with the mother board 50 by electrical connection 62. A temperature sensor 64 is also operably associated with the mother board 50. The temperature sensor 64 is preferably located on the mandrel 40 to within the mandrel sleeve 46 to protect the temperature sensor 64 from corrosive and harmful wellbore fluids and debris that may be present within the wellbore 10.

Strain sensors 66 are located upon or within the mandrel 40 and within the sleeve 46. The strain sensors 66 are preferably bi-directional force sensors that are operable to detect the amount of axial compression or tension placed on the coiled tubing string 22 from the BHA 23 and any downhole tool the BHA 23 might be secured to. The strain sensors 66 are operably connected with the mother board 50 via wired connection 68. The wired connection 68 also interconnects the mother board 50 with torque sensors 70 and impact sensors 72 of types known in the art. The torque sensors 70 are of a type known in the art and are useful for measuring the amount of torque output by a given mud motor. The impact sensors 72 are capable of detecting the amount of jarring force imparted by the jarring tool 24 and transmitted via the fishing tool 28 to the stuck device 15. If desired, the impact sensors 72 may be combined with the strain sensors 66.

The various sensors are all operably interconnected with the mother and/or daughter boards 50, 52 so that sensed variables relating to wellbore conditions can be provided to the data processors on the boards 50, 52. The data storage means on the mother and daughter boards 50, 52 will thereafter store the data associated with each sensed wellbore parameter.

When the BHA 23 is retrieved from the wellbore 10, the stored data can be accessed and used to make changes to the BHA 23 and operating parameters at the surface. Temperature analysis, for example, permits the operator to better determine seal selection, wear, and temperature fluctuations. Sensed measurements from the strain to sensors 66 can be used for a weight-on-bit analysis will permit an operator to know when to “slack off weight” on the coiled tubing 22 to help optimize jarring efforts. FIG. 3 depicts an exemplary process 80 that is useful for optimizing operation of the jarring tool 24 in accordance with the present invention. In step 82 of process 80, a jarring operation is attempted using the BHA 23 with jarring tool 24 and fishing tool 28. In step 84, the processing and storage means of the logging tool 26 stores data provided by the impact sensors 72 as to the effective force provided by the jarring tool 24. In step 86, the processing and storage means of the logging tool 26 stores data provided by the strain sensors 66 relating to the compressive or tensile load placed upon the coiled tubing string 22 proximate the fishing tool 28. The processing and storage means of the logging tool 26 also stores data provided by the flowbore pressure sensor 58 (step 88) and by the temperature sensor 64 (step 90). Assuming that the jarring operation is unsuccessful, the running string 22 and BHA 23 are withdrawn from the wellbore 10 (step 92). Thereafter, the stored data is preferably downloaded or transferred to a surface-based computer and displayed. Operators can thereby examine some or all of the recorded data and analyze it (step 94). The analyzed data is used to make adjustments to the jarring tool arrangement (step 96) prior to attempting to conduct the next jarring operation (step 82). A number of adjustments can be made to the jarring arrangement. Based upon the data received from the impact sensors 72, an operator can increase or decrease the flow rate of fluid through the running string 22 to, respectively, increase/decrease the jarring force imparted by the jarring tool 14. Data from the impact sensors 72 permits analysis of jar output force during fishing operations and allows the operator to reconfigure, reset or alter the jarring tool 14 effectiveness by to changing both the jar mechanical set up at and the surface inputs with the coiled tubing injector 20.

Based upon data stored from the strain sensors 66, an operator can increase or decrease slack-off weight on the coiled tubing string 22 during the next run to improve the effectiveness of the jarring operation. Data stored from the flowbore pressure sensor 58 will permit an operator to determine whether there is a problem in the running string 22 which is preventing fluid from reaching the jarring tool 24. Flow rates through the coiled tubing 22 can be established or adjusted for optimum effectiveness of the jarring tool 24. While flow rate is measured at surface, the flow rate effectiveness proximate the jarring tool 24 is determined by measuring the fluid pressure within the flow bore 44 with tubing pressure gauge 58. An increase in flow rate of fluid through the coiled tubing 22 and flowbore 44 will generally correspond to an increase in the output force provided by the impact jar tool 24 while a decrease in fluid flow rate will generally correspond to the decrease in the output force provide by the jarring tool 24.

Data recorded from the temperature sensor 64 will indicate to an operator whether the downhole temperatures threaten the integrity of fluid seals and indicate that it might be desirable to change flexible seals used in the jarring arrangement.

Similar analyses can be conducted by incorporating the logging tool 26 in other work strings within a wellbore. In these instances, a similar general method would be conducted of incorporating the logging tool 26 into the work string having a work tool and disposing the work string and logging tool 26 into the wellbore. Preferably, the logging tool 26 is to be incorporated into or near the BHA of the work string. The work tool of the work string is then operated, i.e., milling, drilling, work-over and so forth, and the work string then removed from the wellbore. Thereafter, data recorded by the logging tool 26 is analyzed. Two further examples of this technique are now described and shown in FIGS. 4 and 5.

FIG. 4 illustrates an exemplary wellbore 100 which is being drilled into the earth 12 by a drilling arrangement 102. The exemplary drilling arrangement 102 includes a running string formed of coiled tubing 22 that is being disposed into the wellbore by a coiled tubing injection unit 20. The drilling arrangement 102 includes a drilling BHA, generally indicated at 104. The drilling BHA 104 includes a drill bit 106 of a type known in the art which is rotated within the wellbore 100 to drill. The drilling BHA 104 also includes a mud motor 108 of a type known in the art which drives rotation of the drill bit 106. Fluid flowed from the surface 16 downward through the coiled tubing running string 22 will cause the mud motor 108 to rotate the bit 106. The drilling BHA 104 also includes a logging tool 26 of the type described earlier.

An inclination analysis can be conducted with data provided by inclination sensors, of a type known in the art, that are preferably carried on-board the mother and daughter boards 50, 52. The inclination sensors detect the angular inclination of the logging tool 26, and thereby the drilling BHA 104, from vertical.

Torque analysis from data provided by the torque sensors 70 permits the end user to determine the exact amount of torque output by mud motor 108 on the coiled tubing 22 and permits a detailed understanding of the effects of torque on the coiled tubing 22, the motor for wear and efficiency and the device being milled out for consistency of removal of a certain manufacturer's device. Data provided by the torque sensors can be analyzed to determine a build angle of the mud motor during drilling operations and to determine if the build angle increases or decreases with torque.

FIG. 5 once more depicts exemplary wellbore 10 with perforations 18. In the illustrated instance, a work string of coiled tubing 22 is being used to dispose a scale clean-out BHA 110 into the wellbore 10 in order to clean scale proximate the perforations 18. The scale clean-out BHA 110 includes a scale cleaning tool in the form of a jetting nozzle 112 that is used to spray scale cleaning chemicals into the wellbore 10 proximate the perforations 18. An exemplary logging tool 26 is also incorporated into the BHA 110. The pressure differential upon the scale clean-out BHA 110 can be determined by the data processors by comparing the pressure sensed by the annulus pressure sensor 54 to the tubing pressure sensed by the tubing pressure sensor 58, thereby providing pressure determinations both internal and external to the BHA 110. The calculation to pressure differential between the annulus via annulus pressure sensor 54 and the interior flowbore 44 with flowbore pressure sensor 58 is preferably performed by the processing means and the results stored within the storage means. When this data is downloaded to a surface-based computer, it may be viewed in, for example, graph form. This pressure differential analysis allows an operator to determine if sufficient pump pressure is being applied downhole at the scale cleaning tool 112 during scale clean out operations.

The inclination sensors provide detailed and knowledgeable data to ensure for example that the correct lateral entry was achieved and that the correct lateral was treated for a given problem, such as chemical placement for perforation 18 clean out. Analysis of angular departure from the vertical will prevent problems such as damaged formations, costly miss runs and increased exposure at the wellhead during lateral clean out procedures.

The ability to acquire all of the above data analysis with a flow through sensor assembly dramatically increases intervention awareness, BHA effectiveness and operational efficiency.

In a preferred embodiment, the sensor system of the logging tool 26 incorporates a non-magnetic material that is manufactured to house all of the above sensors in a battery powered, memory based system incorporating both electronic and firmware systems to acquire, analyze, register and store all collected data for analysis at surface once downloaded to a surface PC.

The foregoing description is directed to particular embodiments of the present invention for the purpose of illustration and explanation. It will be apparent, however, to those of skill in the art that many modifications and changes to the embodiment set forth above are possible without departing from the scope and the spirit of the invention.

Claims

1. A logging tool for use in connection with a work string within a wellbore, the logging tool comprising: a tool body having axial ends with connections for incorporation into the work string;an axial flow passage disposed within the tool body;one or more sensors for determining at least one wellbore condition relating to the operation of the work string and providing one or more data signals indicative of the at least one wellbore condition; anda processing and storage means within the tool body for storage of data signals provided by the one or more sensors.

2. The logging tool of claim 1 wherein the one or more sensors comprise a strain sensor for determining axial loading upon a running string for the logging tool.

3. The logging tool of claim 1 wherein the one or more sensors comprise an impact sensor for determining impact force.

4. The logging tool of claim 1 wherein the one or more sensors comprise an inclination sensor.

5. The logging tool of claim 1 wherein the one or more sensors comprise a temperature sensor.

6. The logging tool of claim 1 wherein the one or more sensors comprise a pressure sensor.

7. The logging tool of claim 1 wherein the tool body comprises: a radially interior mandrel;an isolation sleeve radially surrounding the interior mandrel; andwherein the processing and storage means is located radially between the mandrel and the sleeve.

8. A work arrangement for a wellbore comprising: a running string;is a work tool that is disposed within the wellbore by the running string to perform an operation within the wellbore;a logging tool carried by the running string to detect and record one or more operational conditions relating to operation of the work tool within the wellbore.

9. The work arrangement of claim 8 wherein: the work tool comprises a jarring tool; andthe logging tool detects and records operational condition data from the group consisting essentially of: impact data relating to the jarring tool, compression/tension on the running string, flow bore pressure within the running string, and temperature.

10. The work arrangement of claim 9 wherein: the work tool comprises a drilling assembly; andthe logging tool detects and records operational condition data from the group consisting essentially of: torque, work tool inclination, flowbore pressure, annulus pressure, and weight-on-bit.

11. The work arrangement of claim 9 wherein: the work tool comprises a scale cleaning tool; andthe logging tool detects and records operational condition data from the group consisting essentially of: flowbore pressure, annulus pressure, and inclination.

12. The work arrangement of claim 9 wherein the running string comprises coiled tubing.

13. The work arrangement of claim 9 wherein the logging tool comprises: a tool body having axial ends with connections for incorporation into the work string;an axial flow passage disposed within the tool body;one or more sensors for determining at least one wellbore condition relating to the operation of the work string and providing one or more data signals indicative of the at least one wellbore condition; anda processing and storage means within the tool body for storage of data signals provided by the one or more sensors.

14. The work arrangement of claim 13 wherein the tool body comprises: a radially interior mandrel;an isolation sleeve radially surrounding the interior mandrel; andwherein the processing and storage means is located radially between the mandrel and the sleeve.

15. A method of operating a work arrangement within a wellbore, the method comprising the steps of: disposing a work arrangement into the wellbore, the work arrangement having a running string, a work tool carried by the running string for performing an operation within the wellbore, and a logging tool carried by the running string to detect and record data relating to one or more operational conditions relating to operation of the work tool within the wellbore;operating the work tool;detecting and recording the data with the logging tool;removing the work arrangement from the wellbore;analyzing the data; andadjusting operational parameters for the work tool.

16. The method of claim 15 wherein: the step of operating the work tool comprises operating a jarring tool; andthe detected and recorded data includes data from the group consisting essentially of: impact data relating to the jarring tool, compression/tension on the running string, flow bore pressure within the running string, and temperature.

17. The method of claim 15 wherein: to the step of operating the work tool comprises operating a drill bit; andthe detected and recorded data includes data from the group consisting essentially of: torque, work tool inclination, flowbore pressure, annulus pressure, and weight-on-bit.

18. The method of claim 15 wherein: the step of operating the work tool comprises operating a scale cleaning tool; andthe detected and recorded data includes data from the group consisting essentially of: flowbore pressure, annulus pressure, and inclination.