Downhole force measurement

An apparatus for measuring forces acting on a tubing string within a wellbore, comprising a body including a central passage and an internal void radially offset from the central passage. End portions extending from the body each include an internal passage and an interface configured to detachably couple to the tubing string for conveyance within the wellbore. A clamp is detachably coupled to one end portion, and first sensors coupled to the clamp are configured to detect strain induced by forces acting on the tubing string. At least one second sensor coupled to the body is configured to detect pressure and temperature within the wellbore. A memory device coupled to the body within the internal void is configured to log measurements detected by the first and second sensors. An electrical power supply coupled to the body within the internal void is configured to provide electrical power to the memory device.

BACKGROUND

U.S. Pat. No. 4,662,458 is directed towards interpreting measurement-while-drilling (MWD) data to predict the direction of advance of a drill bit and evaluate mechanical properties of formations encountered by the drill bit. Specifically, the '458 patent describes sensing devices provided to measure the weight-on-bit and torque of the bit, as well as shear forces and bending moments working on the bit. The sensing devices produce a set of downhole force-moment measurements which can be resolved by calculations to produce the complete loading at the bit. These calculations can then be used, through bottom hole assembly deformation analysis, to detect abnormal deviation tendencies, detect formation interface and lithology change, predict advance directions for the drill bit, and instantaneously adjust operating conditions to control drilling direction.

However, the '458 patent fails to provide for the measurement of downhole forces during downhole operations other than drilling. Those skilled in the art readily appreciate the vast difference between the tools and equipment employing during drilling versus those utilized during non-drilling operations. Moreover, operating conditions such as tension, compression, torque, acceleration, pressure and temperature can be quite different during non-drilling operations relative to those encountered during drilling operations. Additionally, the '458 patent only provides measurements of forces acting on the drill bit, and fails to describe measurements of forces acting on any other section of the drilling, working, or other string being utilized within an existing borehole. Further yet, the '458 patent fails to describe downhole measurements other than force measurements, and thus provides no suggestion regarding the measurement of acceleration, pressure or temperature, among other operating conditions and parameters, whether such measurements are in regard to the drill bit or any other section of the string. The '458 patent also fails to describe logging any downhole measurements of force or other operating conditions and parameters, but instead only describes the immediate transmission of measurement data to a receiver located at the wellbore surface.

DETAILED DESCRIPTION

Referring toFIG. 1, illustrated is side view, in partial section, of an apparatus100according to one or more aspects of the present disclosure. The apparatus100is configured for measuring forces and other parameters at downhole locations in applications other than drilling applications, and with apparatus other than drilling apparatus. The apparatus100includes a body110, an upper end portion120, a lower end portion130, and a sensor assembly140.

In an exemplary embodiment, the end portions120and130may be integral to the body110. That is, the body110and the end portions120and130may be manufactured from a single, discrete billet of metal or other material, such as by machining, casting, injection-molding, electro-discharge machining, and/or other manufacturing processes. Alternatively, one or both of the end portions120and130may be initially manufactured as a discrete component which is subsequently assembled to the body110, such as by welding, threaded fasteners, and/or other assembly means.

The upper and lower end portions120and130may each be substantially cylindrical, possibly having an outer diameter “d” that is substantially less than an outer diameter “D” of the body110. The upper and lower end portions120and130also include upper and lower interfaces120aand130a, respectively. The interfaces120aand130aare configured to detachably couple the apparatus100to or within a tubing string such that the apparatus100can be conveyed within a wellbore. Thus, for example, the interfaces120aand130amay comprise industry-standard pipe threads, although other interfaces are also within the scope of the present disclosure.

FIG. 2is a top view of the apparatus100, andFIG. 3is a sectional view of the apparatus100, as shown inFIG. 1. Referring toFIGS. 1-3, collectively, a central passage150extends through the upper end portion120, the body110, and the lower end portion130. The central passage150may be composed of more than one aperture or, as depicted in the exemplary embodiment ofFIGS. 1-3, the central passage150may be a single through-hole extending along the entire length of the apparatus100. In either case, the central passage150is configured to align, engage, and/or otherwise cooperate with an internal passage of a tubing string to convey fluids and/or other materials along the tubing string.

The body110includes at least one elongated void extending along a substantial length of the body110in a position that is radially offset from the central passage150. For example, in the exemplary embodiment shown inFIGS. 1-3, the body110includes elongated voids160and170. The apparatus100also includes a memory device180and an electrical power supply190, which may be received by and coupled within the elongated voids160and170, respectively. Consequently, the elongated voids160and170may be sized and/or otherwise configured based on the size of the memory device180and power supply190. The memory device180may be or comprise at least a memory portion of a Panex Model 3575 MRO, and the power supply190may be or comprise one or more lithium and/or other type of batteries.

The apparatus100may also include at least one plug fluidicly sealing one or more of the elongated voids. For example, in the exemplary embodiment shown inFIGS. 1-3, the memory device180and the power supply190are fluidicly isolated from the environment of the wellbore by detachable plugs185and195, respectively, which each form a fluidic seal with the internal surface of the voids160and170, respectively, and/or the end110aof the body110. The plugs185and195may each also be or comprise an electrical feed-through, thereby enabling electrical interconnection of the memory device180, power supply190, and/or other electrical components housed within the voids160and170. Thus, for example, an electrical conductor198may interconnect the plugs185and195. The electrical conductor198may comprise stainless or other steel tubing enclosing one or more wires, optical fibers, and/or other electrical signal conductors.

As the elongated voids160and170may extend along the entire length of the body110, the apparatus100may include additional plugs fluidicly sealing the voids at the opposite end110bof the body110. For example, in the exemplary embodiment shown inFIGS. 1-3, fluidic isolation of the power supply190is completed by an additional detachable plug197forming a fluidic seal with the internal surface of the void170and/or the end110bof the body110. However, as most clearly depicted inFIG. 1, the plug197may not comprise an electrical feed-through, but may merely seal the end of the void170. The lower end of the void160, on the other hand, may be fluidicly sealed with an additional detachable plug187which does comprise an electrical feed-through. Accordingly, the memory device180fluidicly sealed within the void160can be electrically or otherwise communicably connected with the sensor assembly140via one or more conductors199, which may be substantially similar to the conductor198. Gauges, sensors and/or other measurement devices located within either or both of the voids160and170can have their memory downloaded by removing one or more of the plugs185,187,195,197, thereby providing access to a probe or other electrical connector through which the data can be retrieved.

In an exemplary embodiment, the void160comprises memory and power supply for performing motion and/or force sensing, measurement and/or logging in conjunction with sensors142, whereas the void170comprises sensors, memory and power supply for performing pressure and/or temperature measurement and/or logging. In such an embodiment, as well as others within the scope of the present disclosure, the voids160and170may not be electrically interconnected, whether for power or communication.

For example, a power supply (e.g., one or more lithium batteries) coupled within the void160may be interconnected within the void160with corresponding circuit devices configured to receive and record data from sensors regarding forces acting on the apparatus100, movement of the apparatus100, and/or motion of the apparatus100. Similarly, a power supply (e.g., one or more lithium batteries) coupled within the void170may be interconnected within the void170with corresponding sensors and circuit devices configured to detect pressure and/or temperature within the void170, within the aperture150, and/or within the wellbore environment surrounding the apparatus100. In an exemplary embodiment, one of the voids160and170contains a PANEX strain gauge logging sensor with a lithium battery power supply, and the other of the voids160and170contains a PANEX model 3525AT or 3575MRO downhole digital quartz pressure and temperature logging device with a lithium battery power supply. In other embodiments, the electronic components of the apparatus100(within the voids160and170or otherwise) may be powered through smart pipe, downhole turbine, and/or other means.

Nonetheless, the scope of the present disclosure is not necessarily limited by the particular arrangement of the combination of power supply and/or metrology devices sealed within or connected to the one or more voids (e.g., voids160and170) that are included within the apparatus100. Thus, although at least one embodiment explicitly described herein includes memory components within the void160and power supply components within the void170, such embodiment is only exemplary, and is provided merely for the sake of simplicity, such that those skilled in the art will readily understand that other embodiments are also within the scope of the present disclosure.

FIG. 4is a sectional view of the apparatus100, as shown inFIG. 1. Referring toFIGS. 1 and 4, collectively, the sensor assembly140includes a plurality of sensors142each configured to detect strain induced by forces acting on the tubing string. For example, the sensors142may each be or comprise one or more conventional or future-developed strain gages, including those commercially available from PANEX. In the exemplary embodiment shown inFIG. 4, the sensor assembly140includes six sensors142. However, other embodiments within the scope of the present disclosure may include another number of sensors142.

The sensor assembly140may also include a clamp subassembly comprising a first member144aand a second member144b, as well as a plurality of threaded fasteners (not shown) coupling the first and second members144aand144b. For example, as in the exemplary embodiment shown inFIG. 4, the first member144amay include a plurality of counter-bored apertures146athrough which threaded fasteners pass and engage threaded apertures146bof the second member144b. However, other means for coupling the first and second members144aand144bare also within the scope of the present disclosure. For example, the first and second members144aand144bmay be hingedly coupled, or the entire assembly140may be threaded on to the lower end portion130or other portion of the apparatus100. Further, the sensor assembly140may include a number of members other than the two members (144aand144b) shown in the exemplary embodiment depicted inFIG. 4. In any case, however, the members of the sensor assembly140(e.g.,144aand144b) may be configured to substantially encircle the perimeter of the second end portion130of the apparatus100such that the stress induced in the apparatus100by the tubing string can be detected by the sensors142of the sensor assembly140.

FIG. 5is a side view of the first member144a. Referring toFIGS. 4 and 5, collectively, each of the first and second members144aand144bmay include one or more external recesses148to which the sensors142are coupled. For example, each recess148may be a stepped recess in which the depth at the perimeter of the recess148is less than the depth of the remainder of the recess148. Two of the sensors142may be coupled to a sidewall of each of the recesses148at diametrically opposed locations, whereas the four remaining sensors142may be coupled to the bottom surfaces of the recesses148at angularly distributed positions. For example, the four remaining sensors142may be positioned at an angle “A” relative to one another, on opposing sides of the sensors142that are coupled to the sidewalls of the recesses148. The angle “A” may be about 90°, as in the exemplary embodiment shown inFIG. 4, although other angles are also within the scope of the present disclosure. The sensors142may be coupled within the recesses148by adhesive, chemical bonding, and/or other means. Electrical wires and/or other conductive members149extend within the recesses148from each of the sensors142to the electrical conductor199, which may extend into an aperture in the sidewall of the member144a.

FIG. 6is a partial sectional view of the first member144ashown inFIG. 5, demonstrating the assembly of an optional cover plate610assembled into or over the recess148of the first member144a(depicted by the dashed arrow). The cover plate610shields the sensors142and conductive members149from the ambient environment of the wellbore. For example, the cover plate610may provide a fluid tight seal with the recess148and/or external radius or other profile of the first member144a, such as to isolate the sensors142and conductive members149from fluids existing within the wellbore. The cover plate610may additionally or alternatively protect the sensors142and conductive members149from impact or shock, such as may be encountered when conveying the apparatus100within the wellbore via the tubing string (e.g., tripping in or tripping out).

In an exemplary embodiment, the recess148is stepped so that it can include a sidewall148ato which one or more of the sensors142can be attached, yet in a manner that the recess148can still receive the cover plate610. For example, the thickness “T” of the cover plate610can be about equal to or less than the depth “De” of the first step of the recess148.

The cover plate610may substantially comprise metallic materials, and may couple to the first member144avia threaded fasteners, one or more clamps, interference fit, and/or other means (not shown). The external radius or other profile of the cover plate610may be substantially similar or identical to that of the first member144a. Alternatively, the cover plate610may be recessed within the external radius or other profile of the cover plate610. The apparatus100may also include an additional cover plate, coupled to the second member144b, which may be substantially similar to the cover plate610shown inFIG. 6.

FIG. 7is a partial sectional view of a portion of the apparatus100shown inFIG. 1, demonstrating the assembly of an optional bonnet710into the apparatus100. The bonnet710shields the sensor assembly140, the plugs187and197, and the electrical conductor(s)199from the ambient environment of the wellbore. For example, the bonnet710may provide a fluid tight seal with the body110and/or the end portion130, such as to isolate the sensor assembly140, the plugs187and197, the electrical conductor(s)199, and/or other components of the apparatus100from fluids existing within the wellbore. The bonnet710may additionally or alternatively protect such components of the apparatus100from impact or shock, such as may be encountered when conveying the apparatus100within the wellbore via the tubing string.

The bonnet710may substantially comprise metallic materials, and may couple to the body110and/or the end portion130via a threaded coupling, threaded fasteners, one or more clamps, interference fit, and/or other means (not shown). At one end715, the external diameter or other profile of the bonnet710may be substantially similar or identical to that of the body110, whereas the other end717of the bonnet710may be tapered to or near the external diameter or other profile of the end portion130, such as may facilitate conveyance of the apparatus100within the wellbore.

FIG. 8is a side view of the apparatus100shown inFIG. 1in an embodiment in which the bonnet710shown inFIG. 7is assembled at one end of the body110.FIG. 8further demonstrates that the apparatus100may include an additional bonnet810at the opposite end of the body110. The bonnet810may be substantially similar to the bonnet710shown inFIG. 7, and may be coupled to the body110and/or the end portion120in substantially the same manner as the assembly of the bonnet710to the end portion130.

FIG. 9is a side view of a system900according to one or more aspects of the present disclosure. The system900demonstrates an environment in which the apparatus100ofFIGS. 1-8may be implemented. For example, the system900includes an embodiment of the apparatus100which may be substantially similar to at least one of those shown inFIGS. 1-8or otherwise within the scope of the present disclosure. The apparatus100is assembled within a tubing string910which extends into a wellbore920from a lifting device930located at the surface925of the wellbore920. The lifting device930may comprise a rig or mast having block equipment connecting the tubing string910to a drawworks device for raising an lowering the tubing string910within the wellbore920. However, embodiments utilizing other lifting apparatus are also within the scope of the present disclosure.

As shown inFIG. 9, the apparatus100may be assembled within the tubing string910in an intermediate position, such that the apparatus is distal from both the surface925of the wellbore and the bottom end of the tubing string910. However, the exact position of the apparatus100within the tubing string910may vary within the scope of the present disclosure. Moreover, in the embodiment shown inFIG. 9, the apparatus100is deployed as a single tool. However, other embodiments within the scope of the present disclosure may deploy multiple instances of the apparatus100positioned at critical points in the wellbore920at several points throughout the tubular string910.

The system900shown inFIG. 9may be utilized in implementations for completion, production, injection (e.g., disposal, water flood and enhanced oil recovery), fishing, work-over, and stimulation (e.g., hydraulic fracture treatments, gravel packs, acidizing, and other downhole pumping operations). Data from the apparatus100may be used to calibrate tubular movement/force, torque, drag (friction), and/or shock models.

For example, in completions with “seal-bore” assemblies, excessive movement occurring as the result of injection or production operations can result in the tubing string910being pulled out of packer seals (not shown), which can result in a catastrophic completion failure. These tubular movements, or force changes, can be the result of pressure and/or temperature changes from injection or production operations. The strain, pressure and temperature information obtained by the apparatus100can be utilized to prevent destructive movement downhole.

Another example is for completion implementations utilizing Frac-Pack/Gravel Pack stimulations, wherein wash pipe may be deployed and the forces applied while pumping (injecting) can change. Consequently, subsequent pressure and temperature changes can force the tubing string910upward. If the movement is not properly accounted for, injection ports utilized for the stimulation may not line up, and the job may be aborted due to the inability to inject. However, by utilizing data obtained by the apparatus100, it can be determined whether the inability to inject is a mechanical problem or a true “screen-out” of the stimulation (e.g., where proppant completely fills the void).

The system900may alternatively be a fishing system utilized to retrieve debris or equipment (“fish”) from the wellbore920. For example, the system900may be utilized to determine whether a fish or debris has been located and, subsequently, whether a fishing tool is engaging the fish in an attempt to secure the fish and bring it to the surface. During fishing, it can be difficult to determine when the fishing tools have come into contact with the fish. However, utilizing the apparatus100to monitor the forces and/or shock in the wellbore920can significantly help in these operations. This is particularly true for fishing in deep and/or deviated wells, and if the fish comprises delicate instruments. Utilizing the apparatus100to monitor stress, temperature and pressure within the wellbore920, however, can make the fishing operation more efficient and minimize or even prevent damage to the equipment being fished.

In operation, the apparatus100may collect and store the stress, temperature and pressure data in the onboard memory device180. Alternatively, or additionally, the apparatus100may be connected to equipment at the surface925, such as for real-time readout and data storage. Telemetry to the surface925may be via electrical cable, fiber-optic cable, wireless telemetry and/or other telemetry systems.

The apparatus100may be utilized to provide direct measurement of the forces, shock, and/or movement (strain, torque, acceleration, pressure and/or temperature) acting on the tubing string910, including at depth within the wellbore920. Conventional methods involved estimations or mathematical models to determine such parameters, and were not sophisticated enough to accurately estimate the forces, shock, and/or movement present on the tubing string910, especially for deep and/or deviated wellbores. However, utilization of the apparatus100or others within the scope of the present disclosure can allow direct measurement of forces, shock, and/or movement present on the tubing string910or sections thereof. This data can then be utilized to calibrate the mathematical models, greatly improving their usefulness.

The apparatus100may further allow optimization of the life and operation of the tubing string, whether it is a completion string, work string, production pipe string, or otherwise. The apparatus100may allow for both preventive and corrective actions for the completions, or production pipe program. For example, the apparatus100may allow simultaneously obtaining a combination of tension, compression, torque, acceleration, pressure and/or temperature measurements, with each measurements being selectable and configurable either through the population of the tool with the appropriate sensors or through the outputs of the sensors themselves.

The apparatus100may further be utilized to provide direct measurement of forces and/or movement acting on the tubing string910, which may allow operational decisions to be made while on the job site. Such decisions may include, for example, changes to injection pressures, pump rates and fluids changes, forces acting on fishing tools at depth, and forces acting on jars, as well as determining slack off weight at depth for packer settings, or determining casing or string torque. Moreover, the value for these applications may be enhanced in embodiments in which real-time telemetry is employed.

In view of all of the above andFIGS. 1-9, it should be evident to those skilled in the art that the present disclosure introduces an apparatus for measuring forces acting on a tubing string within a wellbore. At least in one embodiment, the apparatus comprises a body including a central passage and at least one internal void radially offset from the central passage. First and second end portions extend axially from opposing first and second ends of the body, respectively, wherein each of the first and second end portions includes an internal passage aligned with the central passage of the body, and wherein each of the first and second end portions includes an interface configured to detachably couple to the tubing string for conveyance of the apparatus within the wellbore. A clamp is detachably coupled to the second end portion proximate the body, and a plurality of first sensors is coupled to the clamp and is configured to detect strain induced by forces acting on the tubing string. A plurality of second sensors is coupled to the body and is configured to detect pressure and temperature within an annulus-shaped region radially interposing the apparatus and the wellbore. A memory device is coupled to the body within the at least one internal void and is configured to log measurements detected by the plurality of first sensors and the plurality of second sensors. An electrical power supply is coupled to the body within the at least one internal void and is configured to provide electrical power to the memory device.

In an exemplary embodiment, the apparatus may further comprise a bonnet covering the clamp and the second end of the body and having a central aperture through which the second end portion extends. The bonnet may be a first bonnet and the central aperture may be a first central aperture, and the apparatus may further comprise a second bonnet covering the first end of the body and having a second central aperture through which the first end portion extends.

In an exemplary embodiment, the body and the first and second end portions may each be substantially cylindrical, and the body may have a substantially larger diameter relative to the first and second end portions. The first and second end portions may be integral to the body.

In an exemplary embodiment, the clamp may substantially encircle a perimeter of the second end portion. The clamp may have an outer diameter that is substantially smaller than an outer diameter of the body.

In an exemplary embodiment, the apparatus may further comprise at least one plug that fluidicly seals the at least one internal void and includes an electrical feed-through. The at least one internal void may comprise at least one aperture extending the entire length of the body, and the at least one plug may comprise a first plug that fluidicly seals the at least one aperture at the first end of the body and a second plug that fluidicly seals the at least one aperture at the second end of the body.

In an exemplary embodiment, the at least one internal void may include a memory device void and a power supply void, wherein the memory device is coupled within the memory device void and the electrical power supply is coupled within the power supply void. The memory device may be detachably coupled within the memory device void, and the electrical power supply may be detachably coupled within the power supply void. The memory device void and the power supply void may each be an aperture extending the entire length of the body, and the apparatus may further comprise: a first plug that fluidicly seals the power supply void at the second end of the body; a second plug that fluidicly seals the power supply void at the first end of the body and includes a first electrical feed-through; a third plug that fluidicly seals the memory device void at the first end of the body and includes a second electrical feed-through that is electrically connected to the first electrical feed-through; and a fourth plug that fluidicly seals the memory device void at the second end of the body and includes a third electrical feed-through that is electrically connected to the plurality of first sensors.

The present disclosure also introduces a method of monitoring forces acting on a tubing string within a wellbore. At least in one embodiment, the method comprises coupling a force measurement device to the tubing string, wherein the force measurement device includes: a plurality of first sensors configured to detect strain induced by forces acting on the tubing string; one or more second sensors configured to detect pressure and temperature within the wellbore proximate the force measurement device; and a memory device configured to log measurements detected by the first and second sensors. The method further comprises conveying the force measurement device into the wellbore, detecting with the first sensors the strain induced by forces acting on the tubing string, and detecting with the one or more second sensors the pressure and temperature within the wellbore proximate the force measurement device. The detected strain, pressure and temperature is then stored in the memory device.

In an exemplary embodiment, the method may further comprise transmitting the stored strain, pressure and temperature measurements from the force measurement device via telemetry. The method may further comprise performing completion of the wellbore, performing an injection operation within the wellbore, performing a fishing operation within the wellbore, or performing production from the wellbore, while detecting and storing the strain, pressure and temperature. The method may further comprise removing the force measurement device from the wellbore, detaching the force measurement device from the tubing string, and subsequently accessing the detected strain, pressure and temperature data stored in the memory device while the force measurement device is detached from the tubing string.