Patent Description:
In downhole operations such as drilling, geosteering and measurement-while-drilling (MWD) operations, sensor devices are included with a borehole string that measure various parameters of a formation, borehole and/or downhole components. For example, some drilling systems include downhole torque sensors (disposed on, e.g., a drill collar, drill pipe or MWD tool) to measure the torque distribution of a downhole component. Knowledge of the torque on downhole components can be used to selected and/or adjust various operational parameters, such as rotational rate, weight on bit and others. <CIT> discloses an arrangement of the prior art.

In one aspect, a method of estimating torque is provided according to claim <NUM>.

In another aspect, a system for estimating torque is provided according to claim <NUM>. Various optional features are provided by the dependent claims.

The systems and methods described herein provide for measurement of torque on a downhole component (referred to as "downhole torque"). An embodiment of a torque estimation system includes a first set of directional sensors at a first axial location along a downhole component (e.g., a downhole tool, a bottomhole assembly, drill pipe, a drill string, etc.), and a second set of directional sensors at a second axial location along the downhole component. The directional sensors include, for example, magnetometers and/or accelerometers. The system includes a processing device configured to estimate torque experienced by the downhole component based on directional measurements or measurement data from the sets of directional sensors. In one embodiment, the torque is estimated based on an angle of torsion derived from the directional measurements.

Estimation of the torque includes acquiring directional measurements during a non-rotating state of the downhole component, and calculating a static toolface angle (e.g., gravity toolface and/or magnetic toolface) at each axial location. The static toolface angles are compared to estimate a static toolface offset. Estimation of the torque may also include acquiring directional measurements during rotation of the downhole component, calculating a rotating toolface at each axial location, and estimating a rotating toolface offset. The angle of torsion may be estimated based on the static and rotating toolface offsets, and the downhole torque is estimated based on the angle of torsion and torsional properties (e.g., geometric properties and mechanical properties) of the downhole component.

Embodiments described herein present a number of advantages and technical effects. For example, the embodiments allow for estimating torque downhole without the need for strain gauges or other torque sensors. In conventional drilling and energy industry systems, downhole torque is estimated based on force measurements captured by a bridge of strain gauges distributed around a drill collar or other component. In some instances, strain gauges or other torque sensors are not available. The embodiments eliminate the need for torque sensors, thereby allowing for torque estimation in a wider variety of energy industry systems as compared to conventional torque estimation systems.

Some downhole components, such as bottomhole assemblies with directional and steering units, may not have available strain sensors but do have directional sensors. The embodiments allow for torque estimation using existing sensors without having to modify or redesign such tools to include strain sensors, or without having to deploy additional tools to estimate torque.

Referring to <FIG>, an exemplary embodiment of a well drilling, logging and/or geosteering system <NUM> includes a drill string <NUM> that is shown disposed in a wellbore or borehole <NUM> that penetrates at least one earth formation <NUM> during a drilling operation. As described herein, "borehole" or "wellbore" refers to a single hole that makes up all or part of a drilled well. As described herein, "formations" refer to the various features and materials that may be encountered in a subsurface environment and surround the borehole.

In one embodiment, the system <NUM> includes a conventional derrick <NUM> that supports a rotary table <NUM> that is rotated at a desired rotational speed. The drill string <NUM> includes one or more drill pipe sections <NUM> that extend downward into the borehole <NUM> from the rotary table <NUM>, and are connected to a drilling assembly <NUM>. Drilling fluid or drilling mud <NUM> is pumped through the drill string <NUM> and/or the borehole <NUM>. The well drilling system <NUM> also includes a bottomhole assembly (BHA) <NUM>.

The drilling assembly <NUM> may be rotated from the surface as discussed above, using the rotary table <NUM> or a top drive, or may be rotated in another manner. For example, a drill motor or mud motor <NUM> can be coupled to the drilling assembly <NUM> to rotate the drilling assembly <NUM>.

In one embodiment, the drilling assembly <NUM> includes a steering assembly <NUM> connected to a drill bit <NUM>. The steering assembly may be a bent sub steering assembly, a rotary steering assembly or other suitable device or system. The steering assembly <NUM> can be utilized in geosteering operations to steer the drill bit <NUM> and the drill string <NUM> through the formation <NUM>.

In one embodiment, the drilling assembly <NUM> is included in the bottomhole assembly (BHA) <NUM>, which is disposable within the system <NUM> at or near the downhole portion of the drill string <NUM>. The system <NUM> includes any number of downhole tools <NUM> for various processes including formation drilling, geosteering, and formation evaluation (FE) for measuring versus depth and/or time one or more physical quantities in or around a borehole. The tool <NUM> may be included in or embodied as a BHA, drill string component or other suitable carrier.

In one embodiment, one or more downhole components, such as the drill string <NUM>, the downhole tool <NUM>, the drilling assembly <NUM> and the drill bit <NUM>, include sensor devices <NUM> configured to measure various parameters of the formation and/or borehole. For example, one or more formation parameter sensors <NUM> (or sensor assemblies such as MWD subs) are configured for formation evaluation measurements and/or other formation parameters of interest (referred to herein as "evaluation parameters") relating to the formation, borehole, geophysical characteristics, borehole fluids and boundary conditions. These sensors <NUM> may include formation evaluation sensors (e.g., resistivity, dielectric constant, water saturation, porosity, density and permeability), sensors for measuring borehole parameters (e.g., borehole size, and borehole roughness), sensors for measuring geophysical parameters (e.g., acoustic velocity and acoustic travel time), sensors for measuring borehole fluid parameters (e.g., viscosity, density, clarity, rheology, pH level, and gas, oil and water contents), boundary condition sensors, and sensors for measuring physical and chemical properties of the borehole fluid.

The system <NUM> also includes a directional measurement assembly that includes two or more sets of directional sensors <NUM> that are located at various axial locations along the drill string <NUM>, the BHA <NUM> and/or any other downhole component or components. Each set of directional sensors <NUM> includes one or more directional sensors configured to take directional measurements at corresponding axial locations. A "directional measurement" is a measurement of a parameter or property indicative of, or usable to estimate, a directional property of the downhole component. Examples of directional sensors include magnetometers, accelerometers, gyroscopes and others. Directional measurements are typically utilized in directional drilling operations to estimate directional properties of a downhole component, such as toolface, azimuth and inclination.

In one embodiment, the parameter sensors <NUM>, the sets of directional sensors <NUM> and/or other downhole components include and/or are configured to communicate with a processor to receive, measure and/or estimate directional and other characteristics of the downhole components, borehole and/or the formation. For example, the sensors <NUM>, sets of directional sensors <NUM> and/or BHA <NUM> are equipped with transmission equipment to communicate with a processor such as a surface processing unit <NUM> and/or a downhole processor <NUM>.

The surface processing unit <NUM> (and/or the downhole processor <NUM>) may be configured to perform functions such as controlling drilling and steering, controlling the flow rate and pressure of borehole fluid, transmitting and receiving data, processing measurement data, estimating directional properties, estimating downhole torque as discussed further below, and/or monitoring operations of the system <NUM>. The surface processing unit <NUM>, in one embodiment, includes an input/output (I/O) device <NUM>, a processor <NUM>, and a data storage device <NUM> (e.g., memory, computer-readable media, etc.) for storing data, models and/or computer programs or software that cause the processor to perform aspects of methods and processes described herein.

The directional measurement assembly is part of a torque estimation system that includes a processing device (e.g., the surface processing unit <NUM> and/or downhole processor <NUM>) configured to acquire or receive directional measurement data. The processing device estimates torque on a downhole component based on directional measurements and mechanical properties of the downhole component.

<FIG> show an example of a downhole component <NUM>, and torque distribution during drilling. In this example, the downhole component <NUM> is a tubular such as a drill collar, which has a rotation axis A. It is noted that the downhole component is not limited to this example. As shown in <FIG>, during rotation, the downhole component <NUM> is in torsion and experiences torque T in opposing rotational directions. The torque T at a selected axial location is shown in <FIG>, which illustrates the distribution of torsional shear stress τ. As shown, the magnitude of the shear stress increases radially from zero at the center of the downhole component <NUM> to a maximum shear stress τmax at the surface of the downhole component <NUM>. Due to rotation and torsion, directional sensors at different axial locations, which initially have the same orientation (in a plane normal to the component rotational axis), become misaligned, such that their orientations are different. The torque estimation system utilizes this misalignment to estimate torque on the downhole component during rotation.

The torque estimation system utilizes directional measurements taken at different axial locations. The directional measurements are used to calculate the torque at a selected axial location and/or a distribution of torque along an axial length L of a downhole component. An "axial" location refers to a location on a downhole component relative to a longitudinal axis and/or axis of rotation of a component.

In one embodiment, a processing device is configured to determine the difference between the orientation of a first set of directional sensors and the orientation of a second set of directional sensors, which can change over time due to, for example, high frequency changes in the torque downhole. The processing device estimates the downhole torque based on the difference between orientations and one or more mechanical properties of the downhole component.

In one embodiment, the downhole torque is estimated by calculating an angle of torsion between the axial locations. The angle of torsion is then converted to downhole torque using material properties of the downhole component and offset corrections based on the relative orientation of directional sensors along the downhole component and/or string <NUM>.

The torque estimation system can use any of a variety of types of sensors and/or directional measurements. In one embodiment, the sets of directional sensors include accelerometers and/or magnetometers.

Referring to <FIG>, in one embodiment, the torque estimation system estimates the angle of torsion ϕ between a first axial location and a second axial location. <FIG> illustrates a section of a downhole component <NUM> having a length L that extends from a first axial location <NUM> to a second axial location <NUM>. A set of directional sensors are disposed at each axial location <NUM> and <NUM>. Each set of directional sensors has an orientation relative to the downhole component longitudinal axis. This orientation is referred to as the "toolface orientation," the "toolface angle" or simply "toolface.

In the embodiment of <FIG>, two sets of directional sensors are disposed on the downhole component <NUM>. For example, a first set <NUM> of directional sensors is disposed at the first axial location <NUM>, and a second set <NUM> of directional sensors In this embodiment, the first set <NUM> and the second set <NUM> each include a three-axis accelerometer and a three-axis magnetometer.

Each set of sensors is configured to take a directional measurement in the directions of three orthogonal axes. For example, the first set <NUM> includes sensor components oriented along axes x<NUM>, y<NUM> and z<NUM>, which define a first coordinate system. Likewise, the second set <NUM> includes sensor components oriented along axes x<NUM>, y<NUM> and z<NUM>, which define a second coordinate system. The sets <NUM> and <NUM> are separated by the distance L. It is noted that the coordinate systems are specific to each set of sensors, so that rotation of one set relative to the other results in the sets having differently oriented axes.

As shown in <FIG>, the first set <NUM> of sensors outputs a first set of measurement data that includes accelerometer measurements Gxl, Gy1, Gz1, and magnetometer measurements Hx1, Hy1, Hz1. The second set of sensors outputs a second set of measurement data that includes accelerometer measurements Gx2, Gy2 and Gz2, and magnetometer measurements Hx2, Hy2 and Hz2.

The angle of torsion between the two sensor sets can be derived using Hooke's law for shear according to the following equation: <MAT> where Ø is the angle of torsion, Tis the torque across the downhole component <NUM> (in the plane normal to the z-axis), G is the shear modulus and J is the moment of inertia.

For a tubular downhole component such as a drill collar, the moment of inertia J can be calculated according to the following equation: <MAT> where dout is the external diameter of the tubular and din is the internal diameter of the tubular. By combining equations (<NUM>) and (<NUM>), the following equation for the downhole torque can be derived: <MAT>.

L is the distance between the sets <NUM> and <NUM>, which does not substantially change during rotation (e.g., during a drilling run). In addition, the internal and external diameters can also be assumed constant for a given component size. Based on the assumptions that the length L and the diameters do not change, the remaining variable in equation (<NUM>) is the angle of torsion Ø.

Referring to <FIG>, in one embodiment, the angle of torsion is calculated based on a toolface offset between the sets of sensors. The "toolface offset" refers to an angular difference between the toolface of the first set <NUM> of sensors and the toolface of the second set <NUM> of sensors. <FIG> is a projection of the first and second axial locations onto single plane to show the relative orientations of directional measurements.

In this example, the first set <NUM> of sensors generates a measurement Gx1 in the x<NUM> direction and the second set <NUM> of sensors generates a measurement Gx2 in the x<NUM> direction. The first set <NUM> of sensors also generates a measurement Gy1 in the y<NUM> direction and the second set <NUM> of sensors generates a measurement Gy2 in the y<NUM> direction. As shown in <FIG>, due to torsion, the orientations of the measurements are separated by an angle a that represents the sum of angles of torsion and tool face offset between the sensor sets. The angle α can thus be represented by the following equation: <MAT> where TFO stands for tool face offset between the coordinate systems for each sensor set.

The TFO is estimated, in one embodiment, based on the toolface orientation relative to magnetic north, referred to as the "magnetic tool face" (MTF). Alternatively, or in addition to the MTF, the TFO may be estimated based on the toolface orientation relative to the earth's gravitational field, referred to as the "gravity tool face" (GTF). Both MTF and GTF can be used while steering to measure a borehole's orientation at a specific measurement point and plan accordingly.

MTF is typically used for estimating directional properties of a downhole component at low inclinations. For example, MTF is used when the component has an inclination that is less than a threshold of about <NUM> degrees. On the other hand, for higher inclinations, GTF is typically used.

Using either MTF or GTF, both, the tool face offset (TFO) and the angle of torsion ϕ can be determined. In one embodiment, the TFO is calculated based on directional measurements when the downhole component is not rotating (e.g., while taking a survey). This calculated TFO is referred to as "static TFO. " The TFO is again calculated based on directional measurements taken during rotation of the downhole component. The TFO estimated for a rotating component is referred to as "rotating TFO" The angle of torsion ϕ is estimated based on the static TFO and the rotating TFO, and the downhole torque is estimated based on the angle of torsion ϕ and torsional properties (including geometric properties and mechanical properties) of the downhole component.

The TFO may be estimated based on one or more different types of measurements. For example, each set of directional sensors includes an accelerometer and/or magnetometer. Other types of directional measurements, such as gyroscope measurements, may be used. The TFO estimated based on accelerometer measurements is the GTF offset, which is related to orientation relative to high side. The TFO estimated based on magnetometer measurements is the MTF offset, which is related to orientation relative to magnetic north.

For example, if the borehole inclination is less than a threshold value (e.g., <NUM> degrees), the static TFO can be estimated using magnetometers by calculating a difference between the MTF estimated based on the first set <NUM> of sensors and the MTF estimated based on the second set <NUM> of sensors. The static TFO based on MTF can be calculated based on the following equation: <MAT> where (HxSv1,HySv1) is a measurement point generated by a magnetometer of the first set <NUM> of sensors (e.g., while taking a survey), which includes a measurement of the magnetic field (HxSv1) in the x<NUM> direction and a measurement of the magnetic field (HxSv1) in the y<NUM> direction. (HxSv2,HySv2) is a measurement point generated by the second set <NUM> of sensors (e.g., while taking a survey), which includes a measurement of the magnetic field (HxSv2) in the x<NUM> direction and a measurement of the magnetic field (HxSv2) in the y<NUM> direction.

If the borehole inclination is greater than a threshold value (e.g., <NUM> degrees), the TFO can be estimated using accelerometers by calculating a difference between the GTF estimated based on the first set <NUM> of sensors and the GTF estimated based on the second set <NUM> of sensors. The static TFO based on GTF can be calculated based on the following equation: <MAT> where (GxSv1,GySv1) is a measurement point generated by an accelerometer of the first set <NUM> of sensors (e.g., while taking a survey), which includes an accelerometer measurement (GxSv1) in the x<NUM> direction and an accelerometer measurement (GySv1) in the y<NUM> direction. (GxSv2,GySv2) is a measurement point that includes an accelerometer measurement (GxSv2) in the x<NUM> direction and an accelerometer measurement (GySv2) in the y<NUM> direction.

The angle of torsion ϕ is estimated based on the static TFO and the rotating TFO determined using the first and second sets of sensors during component rotation. In one embodiment, the angle of torsion ϕ is estimated based on a difference between the static TFO and the rotating TFO. For example, the angle of torsion ϕ is estimated using one of the following equations.

where rotMTF1 is the rotating MTF estimated based on magnetometer measurements at the first axial location, and rotMTF2 is the rotating MTF estimated based on magnetometer measurements at the second axial location. rotGTF1 is the rotating GTF estimated based on accelerometer measurements at the first axial location, and rotGTF2 is the rotating GTF estimated based on accelerometer measurements at the second axial location.

Rotating toolfaces can be calculated using a variety of approaches. For example, the rotating MTF is estimated based on a magnetometer measurement (Hx, Hy) as follows: <MAT>.

In another example, the rotating MTF is estimated using a state estimation algorithm to estimate the internal state of the downhole component. One type of state estimation includes determining phase, for example, by using a Kalman filter.

If the estimation is based on GTF, the angle of torsion can be calculated using a state estimation algorithm, or an algorithm that estimates a GTF corrected using a low-pass filter and an estimated MTF.

Once the static and rotating toolfaces are determined, and the angle of torsion ϕ is estimated, the downhole torque is estimated therefrom. In one embodiment, the torque T is estimated by applying the estimated angle of torsion ϕ to equation (<NUM>). For example, if accelerometer measurements are used, the equation (<NUM>) for the angle of torsion is inserted into equation (<NUM>) as follows: <MAT>.

The angle of torsion ϕ can be calculated in a variety of ways and is not limited to the specific embodiments and examples discussed above. For example, the angle of torsion ϕ can be determined using a torsional model of a downhole component based on finite element analysis (FEA). The torsional model may be homogeneous, in which the component's outer diameter (OD) and inner diameter (ID) are assumed constant along the length between sensor sets, and is assumed to be homogeneous with respect to its torsional properties.

In another example, the angle of torsion ϕ can be calculated using a heterogeneous model based on FEA that includes multiple portions of a downhole component. The portions may have the same or different torsional properties. By using finite element analysis each element of the downhole component may have individual set of torsional properties, OD, ID and an individual length. The analysis may include generating a matrix of equations for each element. For example, using finite element analysis, equation (<NUM>) can be expressed as follows:
<MAT>
where n is a number of elements i, Ti is the torque for an element, Li is the length of an element, Gi is the shear modulus of the element and Ji is the moment of inertia of the element.

The use of a finer method such as FEA represents a similar procedure as discussed above to estimate downhole torque based on directional measurements. Such as procedure may be able to deliver more accurate results by considering exact characteristics of the downhole component.

Torque may be estimated with varying levels of resolution. Generally, it is desirable to have a high resolution, which is based on the sampling rate of directional measurements. For example, the resolution in degrees of toolface measurements is based on:
<MAT>
where fsHz is the sampling rate and maxRotSpeedHz is the maximum rotational speed of the downhole component.

For example, considering a sampling rate of about <NUM> and a maximum rotational speed of about <NUM>, the resultant tool face resolution is about <NUM> degrees. If the sampling rate is reduced to <NUM>, then the tool face resolution becomes <NUM> degrees. Therefore, a higher sampling rate favors a higher resolution in the tool face and consequently a higher resolution in the estimation of torque.

<FIG> illustrates a method <NUM> for estimating downhole torque during rotation of a downhole component. The method <NUM> includes one or more of stages <NUM>-<NUM> described herein, at least portions of which may be performed by a processor (e.g., the surface processing unit <NUM> and/or downhole processor <NUM>). In one embodiment, the method includes the execution of all of stages <NUM>-<NUM> in the order described. However, certain stages <NUM>-<NUM> may be omitted, stages may be added, or the order of the stages changed.

In the first stage <NUM>, the downhole tool <NUM>, the BHA <NUM> and/or the drilling assembly <NUM> are lowered into the borehole <NUM> during a drilling and/or directional drilling operation. Although the method <NUM> is described herein as part of a drilling and geo-steering operation, it is not so limited, and may be performed with any desired downhole operation in which torque is a factor (e.g., a wireline operation).

In the second stage <NUM>, directional measurements are taken during a non-rotating phase of the operation. For example, the rotation of the drill string is suspended and directional measurements are taken at a first axial location and at a second axial location. Based on the directional measurements, a static toolface offset is estimated as discussed above. The static toolface offset may be estimated based on magnetometer and/or accelerometer measurements.

In the third stage <NUM>, directional measurements are again taken during rotation of the drilling assembly <NUM> and/or the drill string <NUM>. For example, as drilling proceeds and the drill string <NUM> and/or drilling assembly <NUM> is rotated, directional measurements are taken and used to estimate a rotating toolface at each axial location.

In the fourth stage <NUM>, the angle of torsion between the first and second axial location is calculated based on the static toolface offset and the rotating toolface offset. For example, the angle of torsion is estimated using the equation (<NUM>). The downhole torque is then estimated, for example, using equation (<NUM>).

Measurements may be taken at any suitable time or during any selected time period. For example, measurements can be taken periodically or continuously (i.e., according to a selected sampling rate) and calculations performed and transmitted in in real time or near real time.

In the fifth stage <NUM>, the torque estimations are used to plan and/or adjust various operational parameters. For example, torque estimation is used to compare surface and downhole torque and/or energy, and compare the surface and downhole torque to determine drilling efficiency. Torque estimation may be used to select and/or adjust various operational parameters, such as weight-on-bit, rotational speed, rate of penetration, direction (e.g., inclination and azimuth during directional drilling). In addition, torque estimation as described herein can be used to plan an operation, for example, by selecting material and geometric properties of downhole components and planned operational parameters.

As used herein generation of data in "real time" is taken to mean generation of data at a rate that is useful or adequate for making decisions during or concurrent with processes such as production, experimentation, verification, and other types of surveys or uses as may be opted for by a user. As a non-limiting example, real time measurements and calculations may provide users with information necessary to make desired adjustments during the drilling process. In one embodiment, adjustments are enabled on a continuous basis (at the rate of drilling), while in another embodiment, adjustments may require periodic cessation of drilling for assessment of data. Accordingly, it should be recognized that "real time" is to be taken in context, and does not necessarily indicate the instantaneous determination of data, or make any other suggestions about the temporal frequency of data collection and determination.

In support of the teachings herein, various analyses and/or analytical components may be used, including digital and/or analog systems. The system may have components such as a processor, storage media, memory, input, output, communications link (wired, wireless, pulsed mud, optical or other), user interfaces, software programs, signal processors (digital or analog) and other such components (such as resistors, capacitors, inductors and others) to provide for operation and analyses of the apparatus and methods disclosed herein in any of several manners well-appreciated in the art. It is considered that these teachings may be, but need not be, implemented in conjunction with a set of computer executable instructions stored on a computer readable medium, including memory (ROMs, RAMs), optical (CD-ROMs), or magnetic (disks, hard drives), or any other type that when executed causes a computer to implement the method of the present invention. These instructions may provide for equipment operation, control, data collection and analysis and other functions deemed relevant by a system designer, owner, user or other such personnel, in addition to the functions described in this disclosure.

Claim 1:
A method (<NUM>) of estimating torque, comprising:
disposing at least one measurement assembly at a downhole component (<NUM>, <NUM>), the at least one measurement assembly including a first set of directional sensors (<NUM>) disposed at a first axial location (<NUM>) along the downhole component (<NUM>, <NUM>), and a second set of directional sensors (<NUM>) disposed at a second axial location (<NUM>) along the downhole component (<NUM>, <NUM>);
collecting directional measurement data from the first set of directional sensors (<NUM>) and the second set of directional sensors (<NUM>) during rotation of the downhole component (<NUM>, <NUM>); and
estimating, by a processing device (<NUM>,<NUM>), an amount of torque on the downhole component (<NUM>, <NUM>) based on the directional measurement data;
wherein estimating the amount of torque includes calculating an angle of torsion based on a calculated angle between an orientation of the first set of directional sensors (<NUM>) and an orientation of the second set of directional sensors (<NUM>); characterised in that:
collecting the directional measurement data includes measuring a first static toolface angle of the first set of directional sensors (<NUM>) and a second static toolface angle of the second set of directional sensors (<NUM>) when the downhole component (<NUM>, <NUM>) is rotationally fixed, and estimating the amount of torque includes calculating a static toolface offset angle based on a difference between the first static toolface angle and the second static toolface angle.