REDUNDANCY ENHANCED REMOVAL OF PRESSURE-EFFECT OFFSET FOR DRILL BIT STRAIN GAUGE MEASUREMENTS
As a wellbore is extended into a formation, hydrostatic and hydrodynamic pressures change due to variations in drilling mud weight, fluid density, etc. Strain gauges downhole measure forces experienced by drilling equipment also experience strain due to hydrostatic and hydrodynamic pressures. In order to measure strain due to drilling, hydrostatic and hydrodynamic pressure contributions are removed from strain measurement by removal of a pressure-effect offset, which zeroes or tares the strain measurements. Values of the pressure-effect offset can also be monitored to check that strain measurements are accurately zeroed or to monitor wellbore operations and conditions.
The disclosure generally relates generally to earth drilling including mining and earth drilling, e.g., deep drilling, for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells, and more specifically to drill bit strain measurements.
BACKGROUNDDrillstrings and drill bits in a wellbore experience hydrostatic pressure—as a result of drilling fluid density and gravitational forces—and hydrodynamic pressure—as a result of drilling fluid circulation and movement. Pressure is a measure of force per unit area, where such forces can cause strain and deformation of the drillstring and drill bit. Drillstrings and drill bits also experience drilling forces as a result of interaction between the drill bit, drillstring, and formation. The total force experienced can be determined based on the one or more measurement of strain experienced by the drillstring and/or drill bit.
Aspects of the disclosure may be better understood by referencing the accompanying drawings.
The description that follows includes example systems, methods, techniques, and program flows that embody aspects of the disclosure. However, it is understood that this disclosure may be practiced without these specific details. For instance, this disclosure refers to axial strain in illustrative examples. Aspects of this disclosure can be also applied to radial strain and circumferential strain. In other instances, well-known instruction instances, protocols, structures and techniques have not been shown in detail in order not to obfuscate the description.
Overview
Strain gauges downhole measure forces experienced by various types of drilling equipment (e.g., drill pipes, drill bits, etc.). As a wellbore is extended into a formation, hydrostatic and hydrodynamic pressures change due to variations in drilling mud weight, fluid density, etc. In order to calculate drilling forces from strain measurements, the contribution of pressure to the strain measurement is determined (or otherwise approximated) and subtracted or removed from the measurements of strain. The hydrostatic and hydrodynamic pressure contributions to strain measurements are calculated during off-bottom events (with and without fluid flow). During off-bottom events such as stand additions, other drilling forces are negligible, and one or more pressure-effect offset can be calculated. The one or more pressure-effect offset is then used to separate contributions of hydrostatic and hydrodynamic pressure from contributions to measurements of strain from other drilling forces.
Based on values of pressure-effect offsets calculated at various times and/or points during a drilling run, accuracy of calculated pressure-effect offsets is monitored and pressure-effect offsets can be corrected to provide accurate drilling force and strain information. Pressure-effect offset accuracy is checked by comparing multiple methods or instances of pressure-effect offset determination or by comparing a pressure-effect offset value or trend in value to a value or trend in value expected for a wellbore trajectory and conditions.
Hydrostatic and hydrodynamic pressures, which contribute to the pressure-effect offset value, are estimable based on depth, inclination, mud weight, and flow rate data. When mud weight changes are accounted for, hydrostatic pressure generally increases with vertical depth—as the weight of the drilling mud column increases. When mud weight and flow rate changes are accounted for, hydrodynamic pressure generally remains constant from drillpipe stand addition (i.e., addition of one or more drillpipe sections) to drillpipe stand addition. Hydrostatic and hydrodynamic pressure-effect offset values correspond to pressure magnitude and can be calculated for various drillpipe stands (“stands”) and checked for consistency during addition of a stand (“stand addition”) and for consistency between the end of a first stand and the beginning of a second stand. Hydrostatic-pressure-effect offsets are also checked with respect to inclination and depth measured in the wellbore, where inclination affects the rate at which hydrostatic pressure changes. Based on one or more of these methods, pressure-effect offsets are checked qualitatively and/or quantitatively for accuracy and inaccurate values can be discarded. Checking pressure-effect offset values for errors and inconsistencies over time increases robustness of strain gauge measurements and calibrations. As error-checked pressure-effect offset is more robust, this likewise increases robustness of strain-measurement-based determination of forces applied to components of the drill string (e.g., weight on bit (WOB), torque on bit (TOB), bit bending, etc.).
Example IllustrationsDrilling of oil and gas wells is commonly carried out using a string of drill pipes connected together to form a drillstring 106 that can be lowered through a rotary table into a wellbore 108. The drillstring 106 may operate to penetrate the rotary table for drilling the wellbore 108 through subsurface formations 110. The drillstring 106 may include a kelly, drill pipe 112, and a bottom hole assembly (BHA) 114, perhaps located at the lower portion of the drill pipe 112. The example drilling apparatus 100 may also include a drilling rig located at the surface 102 of a well 104, where the drilling rig is not shown here for simplicity.
The BHA 114 may include drill collars 116, a down hole tool 118, and a drill bit 120. The drill bit 120 may operate to create a wellbore 108 by penetrating the surface 102 and subsurface formations 110. The down hole tool 118 may comprise any of a number of different types of tools including a mud pump, MWD tools, LWD tools, and others. The drillstring 106 also includes a strain gauge 132 and can include additional strain gauges. The strain gauge 132 is depicted as proximate to the drill bit 120 and located in the BHA 114, but it should be understood that the strain gauge 132 can be disposed at any location on the drillstring 106—such as outside the BHA 114, at the drill collar 116, internal to or external to the drillstring 106 between the drill collar 116 and the BHA 114, within or associated with one or more down hole tool 118, integrated into the drill bit 120, including within a connection or shank of the drill bit 120. Only the strain gauge 132 is depicted, but multiple strain gauges of the same or different types can be disposed along the drillstring 106 and in different portions of the example drilling apparatus 100. The strain gauge 132 can include a processor and memory or be in communication with a device with a processor and memory.
During drilling operations, a mud pump may pump drilling fluid (sometimes known by those of ordinary skill in the art as “drilling mud”) from a mud pit through a hose into the drill pipe and down to the drill bit 120. The drilling fluid can flow out from the drill bit 120 and be returned to the surface 102 through an annular area 122 between the drill pipe 112 and the sides of the wellbore 108. The drilling fluid may then be returned to the mud pit, where such fluid is filtered. In some embodiments, the drilling fluid can be used to cool the drill bit 120, as well as to provide lubrication for the drill bit 120 during drilling operations. Additionally, the drilling fluid may be used to remove subsurface formation 110 cuttings created by operating the drill bit 120. In some embodiments the drill bit 120, other elements of the BHA 114 (such as the down hole tool 118) or the strain gauge 132 can send communications to a surface-based controller or operator via electronic, pressure (e.g., mud motor or mud pulse telemetry), optical, etc. means of communication.
During drilling operations, the drillstring 106 (perhaps including the kelly, the drill pipe 112, and the BHA 114) may be rotated by the rotary table. In addition to, or alternatively, the BHA 114 or a portion of the BHA 114 may also be rotated by a motor (e.g., a mud motor) that is located down hole. The drill collars 116 may be used to add weight to the drill bit 120. The drill collars 116 may also operate to stiffen the BHA 114, allowing the BHA 114 to transfer the added weight to the drill bit 120, and in turn, to assist the drill bit 120 in penetrating the surface 102 and subsurface formations 110.
The drill bit 120 can contact a bottom 124 (of a vertical wellbore) or lateral end (of a lateral wellbore) of the wellbore 108 in order to advance the progress of the wellbore drilling. The efficiency of drilling and the forces on the drill bit 120 and the BHA 114 are affected by the position of the drill bit 120 relative to the bottom 124 of the wellbore 108. Depth of the drill bit 120 in the wellbore can be measured by the length of the drillstring 106 or other parameters at the surface 102, but in cases where the drill bit 120 experiences vibrations or non-idealities such as axial displacement, bending, stick-slip, etc. forces and loads transferred between the drill bit 120 and the bottom 124 of the wellbore 108 can vary in magnitude during drilling and the drill bit 120 can also experience fits and starts in rotational movement. The transfer of drilling energy from the drill bit 120 to a face of the wellbore 108 can be calculated based on measured forces experienced by the drill bit 120 or the drillstring 106. Weight on bit (WOB) is a measure of the force transferred axially to a terminus of the wellbore 108 and is traditionally measured in pounds (lbs) or thousands of pounds (10001b). Torque on bit (TOB) is a measure of the force transferred rotationally to a side or the terminus of the wellbore 108 and is traditionally measured in pound feet (lb ft). Rotational velocity of the drill bit is measured in rotations per minute (RPM). WOB, TOB, and RPM can be inferred at the surface 102 from remote measurements, such as hook load, mud flow, etc., or can be measured directly at the drill bit 120 or other locations on the drillstring 106 with embedded force measurement devices, such as the strain gauge 132.
The schematic diagram of the strain gauge 140 depicts the forces exerted on the drillstring 106 which are measured by the strain gauge 132 or another example strain gauge. Pressure, which is a force per unit area, is exerted on the outside of a drillstring component as a function of external pressure, flow rate and mud weight 142. Pressure is also exerted on the inside of the drillstring component as a function of internal pressure, flow rate, and mud weight 144. In the absence of additional axial and circumferential strain (i.e., strain caused by WOB) and additional torsional strain (i.e., strain caused by TOB), deformation of the drillstring component is a function of a net strain 146, which is a function of both the internal pressure and external pressure. In cases where no fluid is flowing through or around the drillstring component and where internal pressure and external pressure are equal, the net strain 146 is a function of the hydrostatic pressure. In cases where fluid is flowing, the internal pressure and external pressure are unequal and the net strain 146 is a function of the hydrodynamic pressure. Where the drillstring can be modelled as an elastic spring (i.e., in the linear displacement and proportional force regime), strain in the absence of WOB and TOB can be converted to a pressure—axial strain along the longitudinal axis of the drillstring, circumferential strain along the circumferential direction of the drillstring, etc. In a cylindrical coordinate system for a drillstring, the axial, radial, and circumferential directions can be considered orthogonal, where the circumferential direction can be generally tangential to a circumference of the drillstring and/or wellbore. Other strain models may also be used, where a relationship between displacement, deformation, and force is well-defined.
Hydrostatic pressure is a function of the weight of the fluid column present in the wellbore—where such weight is a function of the mass or density of the drilling mud (i.e., mud weight), height of the column of fluid (i.e., depth of the well), and gravitational force direction (which depends on the lateral and horizontal orientation of the well). Hydrostatic pressure is therefore indicative of well depth, inclination, and mud weight and qualitative determinations of wellbore conditions are made based on changes in hydrostatic pressure if multiple variables are unknown. If only one variable is unknown, it can be solved for using the relationship between hydrostatic pressure, mud weight, well depth, and inclination. As mud weight can change as a result of fluid influx or loss, and as well depth and inclination can vary from planned values or sensor determined values, hydrostatic pressure tracking via strain gauge measurements adds to downhole data collection. Hydrostatic pressure for a vertical fluid column can be calculated using Equation 1, below:
P=μgh (1)
where P is pressure, ρ is fluid density, g is acceleration due to gravity, and h is fluid depth or the height of the fluid column. It should be understood that hydrostatic pressure calculations change due to applied pressure, wellbore inclination, fluid influx, etc. and that appropriate relationships for hydrostatic pressure will vary by application and wellbore geometry. Because hydrostatic pressure is a function of the weight of a fluid column, hydrostatic pressure varies due to changes in values of fluid density (e.g., mud weight), depth (e.g., height of the fluid column), and wellbore inclination (where the gravitational force applied to a fluid column varies based on the direction of the column with respect to gravity).
The hydrostatic pressure-effect offset can be related to hydrostatic pressure— the hydrostatic pressure-effect can be proportional to hydrostatic pressure but may also be related in another manner, such as sub-linearly, exponentially, polynomially, etc. The value of the hydrostatic pressure-effect offset can therefore correspond to or be used for monitoring wellbore conditions and operations. For example, hydrostatic pressure is expected to increase linearly with depth in a vertical wellbore. Deviations from a linear increase in the hydrostatic pressure-effect value as a function of depth can reflect changes in mud weight, wellbore deviation from the vertical, or errors in the hydrostatic pressure-effect calculation.
Hydrodynamic pressure is a function of drilling mud characteristics (e.g., mud weight, viscosity, density, diffusivity, etc.) and fluid flow rates. The hydrodynamic pressure-effect offset can be proportional to a factor representing a combined flow rate and mud weight. The hydrodynamic pressure-effect offset can be proportional to the hydrodynamic pressure or may be related in another manner, such as those described for the hydrostatic pressure and hydrostatic pressure-effect offset. In some embodiments, a single equation can describe the relationship between a pressure-effect offset or other strain gauge measurement and a pressure. In other embodiments, the relationship can be described by various equations or different equations for certain strain and/or pressure ranges. For example, small pressures can cause a linear change in the strain gauge measurements (i.e., a proportional pressure-effect offset) while large pressures may cause a sublinear or super-linear change in the strain gauge measurements as the strain gauge experiences greater deformation. The relationship between pressure and pressure-effect offset can vary based on strain gauge type, strain gauge orientation, strain gauge filament material, temperature, etc.
With additional surface data (such as average mud weight, drilling mud volume, mud density as a function of pressure, fluid throughput rate, mud motor speed, etc.), flow rate and mud weight values can be calculated based on hydrodynamic pressure. During drilling, the calculated flow rate and mud weight values are monitored and inform control and correction—where flow rates vary due to ball up, nozzle blockages, nozzles blow outs, etc. and mud weight varies due to fluid influx and loss. For strain gauges in communication with a drilling controller, such as at the surface, determination of hydrostatic and hydrodynamic pressure allows and improves real-time (or quasi-real-time or intermittent) trouble shooting for drill string components and control and correction of drilling operations. Hydrodynamic pressure can be calculated using Bernoulli's equations for incompressible flow, such as Equation 2 (below) if the drilling mud is approximately incompressible:
where v is the fluid flow velocity at a point on a streamline, z is the elevation of the point above a reference plane, and the constant is of equal value for all points along a streamline. Other equations can be used to determine hydrodynamic pressure, including the Hagen-Poiseuille equation for laminar flow and general diffusion equations derived from on Fick's laws of diffusion. Appropriate hydrodynamic pressure calculation will vary based on wellbore geometry and drillstring geometry and flow characteristics including flow characteristics encompassed by dimensionless numbers such as the Mach number, Reynolds number, etc.
Because hydrodynamic pressure is a function of the viscosity, density, flow rate, flow regime, and wellbore and drillstring geometry (i.e., tubular versus square), hydrodynamic pressure varies due to changes in values of fluid density (e.g., mud weight), fluid viscosity (e.g., mud composition where oil-based muds and water-based muds can vary in viscosity), wellbore and drillstring geometry (i.e., clearance between wellbore and drillstring which can be effected by drill bit gauge and/or wellbore deterioration), fluid speed (e.g., flow rate), etc. The hydrodynamic pressure-effect offset can therefore correspond to or be used for monitoring wellbore conditions and operations. For example, hydrodynamic pressure is expected to decrease as flow rate decreases and an unexpected decrease in the hydrodynamic pressure-effect offset can correspond to a decrease in flow rate caused by a loss in drilling mud circulation (e.g., a loss of drilling mud to the formation) or errors in the hydrodynamic pressure-effect offset calculation.
The pressure-effect offset calculator 150 operates on strain measurements obtained during a stand addition, component addition, or other pause in drilling. Drill pipe is added to the drillstring 106 in sections, called stands, where drilling and mud flow are paused during stand additions and the drillstring 106 is pulled off-bottom 128 of the wellbore 108. Drilling can be paused during the addition of each stand or any drillstring or wellbore component. Drilling can also be paused to switch or replace a drillstring, wellbore, or drilling rig component where no component is actually added to the drillstring. Drilling may also be paused to take one or more measurements (i.e., magnetometer, accelerometer, directional measurements, etc.) or transmit data (for example, nuclear magnetic resonance (NMR) data sets), where measurements can coincide with stand additions but can also be triggered independently of stand additions—such as to acquire or transmit higher quality or resolution data. Hereinafter “stand addition” should be understood to also encompass any pause in drilling or other off-bottom event during which WOB is substantially lower than during active drilling and during which mud flow and mud motor or drill bit rotation may or may not be paused, whether or not a stand or other component (e.g., drill collar, stabilizer, tool, etc.) is added to the drillstring. During the stand addition, the WOB approaches a local minimum and the TOB and the RPM approach approximately or substantially zero. The pressure-effect offset calculator 150 can be located at the surface 102 or at the drill bit 120 or at another location within the wellbore 108. The pressure-effect offset calculator 150 is in communication with the strain gauge 132 or part of the strain gauge 132. The pressure-effect offset calculator 150 can operate in real time or operate based on strain measurements collected during a drilling run after the completion of the drilling run, such as when the strain gauge 132 is tripped out or otherwise removed from the wellbore 108.
A graph 152 depicts strain measurements obtained during a drilling run, where WOB is at a minimum during stand additions. The graph 152 depicts portions of the drilling run where strain values 156 and strain values 157 correspond to stand additions or other elements where drilling is paused or otherwise in an off-bottom regime 158. The graph 152 also depicts portions of the drilling run where strain values 160 correspond to WOB for an on bottom drilling regime 162.
The strain measurements of the graph 152 can be axial strain measurements (i.e., measurements of strain along the longitudinal axis of the drillstring), can be radial or circumferential strain measurements (i.e., measurements of strain along the radial axis of the drillstring or along the tangential direction of an outer radius of the drillstring), or be can strain measurements for another axis or along a combination of axes. The strain measurements of the graph 152 can also be obtained from a strain gauge which can measure in more than one strain direction or along more than one axis, either at the same time or be moved to measure strain in different directions. Hereinafter “strain measurements” should be understood to encompass axial strain measurements, circumferential strain measurements, radial strain measurements, and combinations thereof.
The pressure-effect offset calculator 150 identifies the strain values 156 and the strain values 157 corresponding to the off-bottom regime 158. The pressure-effect offset calculator determines a pressure-effect offset based on the strain measurements at various times during drilling. The pressure-effect offset calculator determines a pressure-effect offset from each of the strain values 156 and/or the strain values 157. A hydrostatic pressure offset 164 is determined based on strain values which correspond to an off-bottom, no fluid flow event or portion of the stand addition. A total pressure offset 166 is determined based on strain values which correspond to an off-bottom, fluid flowing even or portion of the stand addition. The total pressure offset 166 can also be a hydrostatic-and-hydrodynamic pressure offset—where hydrostatic pressure and hydrodynamic pressure together constitute substantially all pressure experienced in the wellbore. That is, the total pressure, and therefore the total pressure offset, corresponds to the hydrostatic pressure (and hydrostatic pressure offset) and the hydrodynamic pressure (and the hydrodynamic pressure offset) when other contributions of pressure (such as atmospheric pressure, explosive pressure, surface pressure or surface tension, etc.) are negligible when compared to the hydrostatic pressure and hydrodynamic pressure. Based on the hydrostatic pressure offset 164 and the total pressure offset 166, the pressure-effect offset calculator 150 determines a value for a hydrodynamic pressure offset 168. The pressure-effect offset calculator 150 can output one or more of the hydrostatic pressure offset 164, the total pressure offset 166, and the hydrodynamic pressure offset 168 to a controller or operator at the surface 102 during a drilling run, such as via fiber optic telemetry, pressure (i.e., mud pulse) telemetry, etc. The pressure-effect offset calculator 150 can also store in memory or communicate for storage in memory one or more of the hydrostatic pressure offset 164, the total pressure offset 166, and the hydrodynamic pressure offset 168 to a controller or operator at the surface 102 during a drilling run for post-drilling analysis. Alternatively, the pressure-effect offset calculator 150 can operate at the surface 102 based on strain measurements communicated during a drilling run, such as via fiber optic telemetry, acoustic (i.e., mud pulse) telemetry, etc. or on strain measurements previously stored in memory.
The pressure-effect offset calculator 150 can also identify various portions of the strain addition (such as the off-bottom regime 158 (which can comprise both the no flow and off bottom regime and the off bottom with mud flow regime), the on bottom drilling regime 162, etc.) with a trained machine learning algorithm. The machine learning algorithm can be trained on one or more of WOB, TOB, and RPM measurements or strain measurements to identify stand additions and/or portions of stand additions based on the same measurements or fewer measurements. For example, the machine learning algorithm can be trained using supervised training to identify the no flow and off bottom regime based on strain measurements, where the no flow and off bottom regime in the training data is identified using both WOB and TOB measurements.
The error checker 180 can then determine redundancy enhanced strain measurements 170, based on one or more of the hydrostatic pressure offset 164, the total pressure offset 166, and the hydrodynamic pressure offset 168. The error checker 180 can also optionally operate on one or more of the hydrostatic pressure offset 164, the total pressure offset 166, and the hydrodynamic pressure offset 168 together with wellbore path information 172 and/or hydrodynamic information. The wellbore path information 172 can include a wellbore path trajectory, inclination, drill bit geolocation, etc. or any other information about a planned or executed wellbore path. The hydrodynamic information 174 can include information about mud weight and mud flow rate, either actual or predicted. The error checker 180 can detect a change in wellbore or wellbore operation status or condition based on the values of one or more of the hydrostatic pressure offset 164, the total pressure offset 166, and the hydrodynamic pressure offset 168. The error checker 180 can also detect a change in accuracy, an error, or a value which falls outside a predicted or current trend in one or more of the hydrostatic pressure offset 164, the total pressure offset 166, and the hydrodynamic pressure offset 168. The error checker 180 can identify or tag as erroneous a value of one or more of the hydrostatic pressure offset 164, the total pressure offset 166, and the hydrodynamic pressure offset 168 and optionally replace an erroneous value with a previous value of the quantity that was not identified as erroneous or a value that is interpolated or projected using two or more values of the quantity that were not identified as erroneous.
The error checker 180 can operate proximate to the pressure-effect offset calculator 150, such as at the drill bit 120 or at the surface 102. The error checker 180 can also operate at the surface 102 based on communications received from the pressure-effect offset calculator 150, either during drilling or based on previously collected data. The error checker 180 can communicate to a controller or operator at the surface 102 during a drilling run, either from within the wellbore 108 or from another location at the surface 102. The error checker 180 can also be integrated within a controller or other processor at the surface 102.
At block 202, the pressure-effect offset calculator detects a stand addition for a drillstring in a wellbore. The pressure-effect offset calculator can detect the stand addition based on communication from a drilling operation controller, which may initiate or detect the stand addition and communicate to the pressure-effect offset calculator that a stand addition is occurring, will occur, or has occurred. The drilling operator controller may also flag data, such as WOB, TOB, RPM, with a stand addition indicator, for both real time data and historical data. The pressure-effect offset calculator can detect the stand addition based on WOB measurements and, optionally, TOB and RPM measurements, either in real time or based on historical data. The pressure-effect offset calculator can determine the stand addition based on statistical or other analysis of the WOB measurements, such as detecting a local minimum or other feature corresponding to a stand addition or off-bottom event. The pressure-effect offset calculator can also detect the stand addition based on a value threshold, a first derivative or other rate of change value, an average value, a standard deviation value, a bandwidth threshold for a rolling window of values, etc. determined from WOB measurements. The pressure-effect offset calculator can detect the beginning of a stand addition, the beginning and end of a stand addition, or can detect individual portions of the stand addition separately—such as the no flow off bottom regime and the off bottom with mud flow regime. The pressure-effect offset calculator can also detect stable measurements or a set of stable measurements corresponding to the stand addition or either of the regimes.
The pressure-effect offset calculator can detect the stand addition based on analysis of WOB measurements in conjunction with TOB measurements and/or RPM measurements. The pressure-effect offset calculator can determine the stand addition based on statistical or other analysis of the TOB measurements, such as detecting a local minimum where TOB measurements are substantially zero or another feature corresponding to the stand addition or off-bottom event. As TOB measurements are calibrated based on torsional strain detectors, TOB measurements may be greater than zero (or even negative) if calibrations contain inaccuracies. A substantially zero TOB measurement can therefore correspond to a local minimum or global minimum value for TOB that is not zero but can be approximately zero or zero to within a threshold. The pressure-effect offset calculator can detect a range or set of times for which TOB measurements indicate a stand addition, and then identify WOB measurements corresponding to the stand addition based on measurement times. The pressure-effect offset calculator can also use the TOB measurements to validate or invalidate a stand addition detected in WOB measurements. The pressure-effect offset calculator can also detect the stand addition based on a value threshold, a first derivative or other rate of change value, an average value, a standard deviation value, a bandwidth threshold for a rolling window of values, etc. determined from TOB measurements.
The pressure-effect offset calculator can determine the stand addition based on statistical or other analysis of the RPM measurements, such as detecting a local minimum where RPM measurements are substantially zero or detecting another feature corresponding to the stand addition or off-bottom event. As RPM measurements are calibrated based on rotational velocity sensors, RPM measurements may be greater than zero (or even negative) if calibrations contain inaccuracies. RPM measurements can also be greater than zero even if the drill bit is not being rotated, such as due to momentum from previous rotation. RPM measurements can also account for more than one source of rotation (i.e., rotation of a drill bit by a positive displacement motor, rotation of a drillstring at the surface of a wellbore, etc.), where various sources of rotation can be shut off at different times and/or incompletely stopped. A substantially zero RPM measurement can therefore correspond to a local minimum or global minimum value for RPM that is not zero but can be approximately zero or zero to within a threshold. The pressure-effect offset calculator can detect a range or set of times for which RPM measurements indicate a stand addition, and then identify WOB measurements corresponding to the stand addition based on measurement times. The pressure-effect offset calculator can also use the RPM measurements to validate or invalidate a stand addition detected in WOB measurements, together with or in addition to the TOB measurements. The pressure-effect offset calculator can also detect the stand addition based on a value threshold, a first derivative or other rate of change value, an average value, a standard deviation value, a bandwidth threshold for a rolling window of values, etc. determined from TOB measurements.
At block 204, the pressure-effect offset calculator obtains strain measurements from a strain gauge associated with the drillstring. The pressure-effect offset calculator can obtain strain measurements from the strain gauge for all available times or data points, or for only those times or data points associated with the stand addition. The pressure-effect offset calculator can obtain strain measurements in any appropriate form or unit, such as voltages output by the strain gauge, as WOB measurements or other force measurements, etc. The pressure-effect offset calculator can obtain WOB measurements from a strain gauge located at the drill bit (to identify a stand addition) and additional strain measurements from a strain gauge located at another point on the drillstring. If the pressure-effect offset calculator obtains strain measurements from a strain gauge that does not measure WOB (or measures WOB at a location away from the drill bit), the pressure-effect offset calculator can synchronize or otherwise correlate the strain measurements to WOB and/or other measurements used to identify the stand addition or the stand addition times.
At block 206, the pressure-effect offset calculator identifies a set of strain measurements from the strain gauge corresponding to an off-bottom, no fluid flow portion of the stand addition. The pressure-effect offset calculator can identify the set of strain measurements corresponding to the off-bottom, no fluid flow portion of the stand addition at the same time as the stand addition is detected, or can detect the set of strain measurements corresponding to the off-bottom, no fluid flow portion of the stand addition after a stand addition is identified. The pressure-effect offset calculator can identify an off-bottom portion of the stand addition based on WOB measurements, such as by detecting a local minimum in the WOB measurements. The pressure-effect offset calculator can identify a no fluid flow portion of the stand addition based on the RPM measurements of a drill bit, such as by detecting substantially zero RPM for a drill bit or mud motor pump. The pressure-effect offset calculator can identify the set of strain measurements corresponding to the off-bottom, no fluid flow portion of the stand addition based on an overlap of the off-bottom and no fluid flow portions of the stand addition and based on one or more of the WOB, RPM, and TOB measurements.
The pressure-effect offset calculator can also identify the set of strain measurements corresponding to the off-bottom, no fluid flow portion of the stand addition for which strain measurements are relatively stable. Relatively stable can comprise strain measurements for which a standard deviation or other variance is smaller than a predetermined threshold. Relatively stable can also comprise the set of strain measurements corresponding to the off-bottom, no fluid flow portion of the stand addition for which a rolling average is constant or for which the rolling mean is constant to within a stability threshold. The pressure-effect offset calculator can identify the set of strain measurements corresponding to the off-bottom, no fluid flow portion of the stand addition and then remove strain measurements at the beginning and the end of the set for which values may be less stable. Variations in strain measurements can be caused by the drillstring decompressing (i.e., tension or flexion) after the drillstring is pulled off-bottom, or caused by a drill bit or mud motor starting up or ramping down.
At block 208, the pressure-effect offset calculator optionally filters data of the set of strain measurements corresponding to the off-bottom, no fluid flow portion of the stand addition. The pressure-effect offset calculator can filter the set of strain measurements to determine an average, mean, or mode strain value, or a range of strain values (for example, a mean strain value and a first standard deviation in the strain values). The pressure-effect offset calculator can filter values negatively (i.e., remove values of the set) or positively (i.e., select values for the set). The pressure-effect offset calculator can determine if one or more values of the set of strain measurements corresponding to the off-bottom, no fluid flow portion of the stand addition corresponds to noise or another non-pressure related effect—such as an unexpected weight transfer event like a collision with a side of the wellbore or touching down on the bottom of the wellbore. The pressure-effect offset calculator can alternatively select a portion of the set of strain measurements corresponding to a stable or the most stable portion of the off-bottom, no fluid flow portion of the stand addition.
At block 210, the pressure-effect offset calculator determines a hydrostatic pressure-effect offset value from the set of strain measurements corresponding to the off-bottom, no fluid flow portion of the stand addition based on a zero point for the strain measurements. Strain measurements are usually made in millivolt (mV) per volt (V) or mV/V. The pressure-effect offset calculator can calculate the hydrostatic pressure-effect offset value in the same units as the strain measurements, in equivalent units, or in another unit which can be converted to the units of the strain measurement. Optionally, the pressure-effect offset calculator can convert the strain measurements to another metric (such as pressure measurements in pounds per square inch (psi) or any other appropriate unit, or force measurements in pounds (lbs). The pressure-effect offset calculator can also determine the hydrostatic pressure-effect offset in units of pressure, force, etc. either based on strain measurements or can determine the hydrostatic pressure-effect offset in units of strain measurement and then convert the hydrostatic pressure-effect offset to any other appropriate unit of measure (such as units of strain, which may be dimensionless, units of pressure, units of force, units of energy, etc.).
The pressure-effect offset calculator determines the hydrostatic pressure-effect offset based on a zero point for the strain measurements. The pressure-effect offset calculator can determine that the entirety of the strain measurement value during the off-bottom, no fluid flow portion of the strain measurements corresponds to the hydrostatic pressure-effect offset. The pressure-effect offset calculator can also determine that a portion of the strain measurement value during the off-bottom, no fluid flow portion of the strain measurement corresponds to a zero value for the strain measurement. For example, a strain gauge measures a value of 0 mV/V at a pressure of zero or at the surface of a wellbore before the strain gauge is introduced into the wellbore. The strain gauge then measures a value of 1 mV/V during the hydrostatic portion of a stand addition. Accordingly, the pressure-effect offset calculator determines that the hydrostatic pressure-effect offset is 1 mV/V or the difference between the zero point (i.e., 0 mV/V and the strain measurements of 1 mV/V during the off-bottom, no fluid flow portion of the stand addition). However, the strain gauge may not measure a value of 0 mV/V at the zero point, as a zero point may be chosen arbitrarily, and strain gauge values can be further affected by temperature of the filament or other elements of the strain gauge when the measurement is taken. In a second example, a strain gauge measures a value of 0.1 mV/V at a pressure of zero or at the surface of a wellbore before the strain gauge is introduced into the wellbore. The strain gauge then measures a value of 1.2 mV/V during the hydrostatic portion of a stand addition. In this second example case, the pressure-effect offset calculator determines that a zero-point offset is |0.1| mV/V and the hydrostatic pressure-effect offset is 1.1 mV/V or 1.2 mV/V. That is, the pressure-effect offset calculator can include or exclude an additional zero-point offset. In some cases, such as where temperature varies widely along the wellbore, the pressure-effect offset calculator can preferentially include multiple offsets caused by other-than-pressure effects (i.e., pre-tensioning-effect offset, expansion-effect offset, etc.) within the hydrostatic pressure-effect offset because other offsets are less relevant or much smaller than the pressure-effect offset.
The pressure-effect offset calculator can determine a single value of the hydrostatic pressure-effect offset, can determine a range of values, can determine a mean and standard deviation for a set of values, etc. The pressure-effect offset calculator can optionally filter the values of the hydrostatic pressure-effect offset after determination, instead of filtering the data of the set of strain measurements. The pressure-effect offset calculator can determine multiple values, but store or transmit fewer than all values based on, for example, transmission or storage limitations.
At block 212, the pressure-effect offset calculator outputs the hydrostatic pressure-effect offset value for monitoring of a wellbore operation. The pressure-effect offset calculator can output the hydrostatic pressure-effect offset value to a surface drilling operator or controller. Optionally, the pressure-effect offset calculator can trigger an alert if the hydrostatic pressure-effect value if the hydrostatic pressure-effect value falls outside a predetermined range or displays a change from a previous value greater than a predetermined threshold—i.e., the pressure-effect offset calculator can trigger an alert for a set of predetermined hydrostatic pressure-effect offset values. The pressure-effect offset calculator can output the hydrostatic pressure-effect offset to storage or memory for retrieval after the completion of the drilling run. The pressure-effect offset calculator can also compare a current hydrostatic pressure-effect offset to a hydrostatic pressure-effect offset calculated for a previous stand addition and store the hydrostatic pressure-effect offset for calculation of a hydrodynamic pressure-effect offset in the stand addition.
At block 302, the pressure-effect offset calculator detects a stand addition for a drillstring in a wellbore.
At block 304, the pressure-effect offset calculator obtains strain measurements from a strain gauge associated with the drillstring.
At block 306, the pressure-effect offset calculator identifies a set of strain measurements from the strain gauge corresponding to an off-bottom, no fluid flow portion of the stand addition.
At block 308, the pressure-effect offset calculator optionally filters data of the set of strain measurements corresponding to the off-bottom, no fluid flow portion of the stand addition.
At block 310, the pressure-effect offset calculator determines a hydrostatic pressure-effect offset value from the set of strain measurements correspond to the off-bottom, no fluid flow portion of the stand addition based on a zero point for the strain measurements.
At block 314, the pressure-effect offset calculator identifies a set of strain measurements from the strain gauge corresponding to an off-bottom, fluid flowing portion of the stand addition. The pressure-effect offset calculator can identify the set of strain measurements corresponding to the off-bottom, fluid flowing portion of the stand addition at the same time as the stand addition is detected, or can detect the set of strain measurements corresponding to the off-bottom, fluid flowing portion of the stand addition after a stand addition is identified. The pressure-effect offset calculator can identify the off-bottom, fluid flowing portion of the stand addition while also identifying the off-bottom, no fluid flowing portion of the stand addition, such as in block 306. The pressure-effect offset calculator can identify an off-bottom portion of the stand addition based on WOB measurements, such as by detecting a local minimum in the WOB measurements. The pressure-effect offset calculator can identify the fluid flowing portion of the stand addition based on the RPM measurements of a drill bit, such as by detecting a non-zero RPM for a drill bit or mud motor pump. The pressure-effect offset calculator can also identify the fluid flowing portion of the stand addition or the start of the fluid flowing portion of the stand addition based on an abrupt increase (or a gradual and substantial increase) in RPM and/or TOB corresponding to a ramp up of a drill bit or mud motor pump. The pressure-effect offset calculator can identify the set of strain measurements corresponding to the off-bottom, fluid flowing portion of the stand addition based on an overlap of the off-bottom and fluid flowing portions of the stand addition and based on one or more of the WOB, RPM, and TOB measurements.
The pressure-effect offset calculator can also identify the set of strain measurements corresponding to the off-bottom, fluid flowing portion of the stand addition for which strain measurements are relatively stable. Relatively stable strain measurements can be strain measurements for which a standard deviation or other variance is smaller than a predetermined threshold. Relatively stable strain measurements can be the set of strain measurements corresponding to the off-bottom, fluid flowing portion of the stand addition for which a rolling average is constant or for which the rolling mean is constant to within a stability threshold. The pressure-effect offset calculator can identify the set of strain measurements corresponding to the off-bottom, fluid flowing portion of the stand addition and then remove strain measurements at the beginning and the end of the set for which values may be less stable.
At block 316, the pressure-effect offset calculator optionally filters data of the set of strain measurements corresponding to the off-bottom, fluid flowing portion of the stand addition. The pressure-effect offset calculator can filter the set of strain measurements to determine an average, mean, or mode strain value, or a range of strain values (for example, a mean strain value and a first standard deviation in the strain values). The pressure-effect offset calculator can filter values negatively or positively. The pressure-effect offset calculator can determine if one or more values of the set of strain measurements corresponding to the off-bottom, fluid flowing portion of the stand addition corresponds to noise or another non-pressure related effect. The pressure-effect offset calculator can alternatively select a portion of the set of strain measurements corresponding to a stable or most stable portion of the off-bottom, fluid flowing portion of the stand addition. As an example, the pressure-effect offset calculator can select a subset of the set of strain measurements corresponding to the off-bottom, fluid flowing portion of the stand addition for which a rolling average increases less than a threshold.
At block 318, the pressure-effect offset calculator determines a total pressure-effect offset value from the set of strain measurements corresponding to the off-bottom, fluid flowing portion of the stand addition based on a zero point for the strain measurements. The total pressure-effect offset is a pressure-effect offset for the hydrodynamic regime, which is the off-bottom, fluid flowing portion of the stand addition and includes contributions due to both hydrostatic pressure (which generates the hydrostatic pressure-effect offset) and hydrodynamic pressure (which generates the hydrodynamic pressure-effect offset). The total pressure-effect offset can be any pressure-effect offset associated with the hydrodynamic regime. The pressure-effect offset calculator determines a total pressure-effect offset based on a zero point for the strain measurements, which may be the same zero point used to determine the hydrostatic pressure-effect offset in block 310 (and as previously described with reference to block 210). The zero point for the strain measurements may also be the hydrostatic pressure-effect offset, such as that calculated in block 310 or another appropriate zero-point offset. In some cases, the zero point for the strain measurements can depend on temperature and the hydrostatic pressure-effect offset and the total pressure-effect offset can be determined based on different zero points for the strain measurements if temperature changes between measurements.
At block 320, the pressure-effect offset calculator determines a hydrodynamic pressure-effect offset based on a difference between the hydrostatic pressure-effect offset and the total pressure-effect offset. The hydrodynamic pressure-effect offset is a measure of a change in zero-point offset between the hydrostatic regime, which is the off-bottom, no fluid flow portion of the stand addition, and the hydrodynamic regime, which is the off-bottom, fluid flowing portion of the stand addition. The pressure-effect offset calculator can determine the hydrodynamic pressure-effect offset in any appropriate manner, such as those described in blocks 310 and 320.
The pressure-effect offset calculator determines the hydrodynamic pressure-effect offset based on a difference between the hydrostatic pressure and the total pressure-effect offset, which can be determined in any comparable units such as voltage (e.g., mV/V), current, lbs, psi, etc.
At block 322, the pressure-effect offset calculator outputs the hydrodynamic pressure-effect offset for monitoring of a wellbore operation. The pressure-effect offset calculator can output the hydrodynamic pressure-effect offset to a surface drilling operator or controller. Optionally, the pressure-effect offset calculator can trigger an alert if the hydrodynamic pressure-effect offset falls outside a predetermined range or displays a change from a previous value or from a hydrostatic pressure-effect offset greater than a predetermined threshold—i.e., the pressure-effect offset calculator can trigger an alert for a set of predetermined hydrodynamic pressure-effect offset values. The pressure-effect offset calculator can output the hydrodynamic pressure-effect offset to storage or memory for retrieval after the completion of the drilling run. The pressure-effect offset calculator can also compare a current hydrodynamic pressure-effect offset to a hydrodynamic pressure-effect offset calculated for a previous stand addition. The pressure-effect offset calculator can also output the hydrostatic pressure-effect offset and/or the measure of total pressure-effect offset with the hydrodynamic pressure-effect offset.
Although calculation of both a total pressure-effect offset and a hydrodynamic pressure-effect offset are depicted in
At block 402, the error checker detects a stand addition for a drillstring in a wellbore. The error checker can detect a stand addition as previously described with respect to block 202. The error checker can alternatively detect a stand based on a trigger or data tag from the pressure-effect offset calculator.
At block 410, the error checker determines a hydrostatic pressure-effect offset value for the detected stand. As previously described with reference to
At block 424, the error checker determines a change in the hydrostatic pressure-effect offset value based on a difference between the hydrostatic pressure-effect offset value for the detected stand and at least a previously determined hydrostatic pressure-effect offset value. The error checker can access a previously determined hydrostatic pressure-effect offset from a previous stand. The error checker can store a previously determined hydrostatic pressure-effect offset calculated for the wellbore, such as a predicted pressure-effect offset based on a wellbore model. The error checker can determine a change in the hydrostatic pressure-effect offset value based on multiple previously determined hydrostatic pressure-effect offset values. For example, the error checker can determine if the hydrostatic pressure-effect offset value falls within a standard deviation of a mean of a set of previously determined hydrostatic pressure-effect offset values. In another example, the error checker can determine the change in hydrostatic pressure-effect offset is greater or smaller than a threshold.
At block 426, the error checker optionally determines an expected change in the hydrostatic pressure-effect offset based on a wellbore trajectory. Wellbore trajectory can include at least one of a planned or measured depth, diameter, inclination, orientation, or other trajectory data. The wellbore trajectory can be determined based on one or more sensor measurement or data from one or more tool, including logging while drilling (LWD) and measurement while drilling (MWD) tools. The wellbore trajectory can also include a planned, projected, or predicted wellbore trajectory measurement and a measurement of deviation from the planned wellbore trajectory. The error checker can determine the expected change based on the wellbore trajectory for a drilling run or portion of a drilling run. That is, the error checker can determine the expected change based on the cumulative wellbore trajectory. The error checker can determine the expected change based on a difference in the wellbore trajectory for the detected stand addition and a location associated with the previously determined hydrostatic pressure-effect offset value. That is, the error checker can determine the expected change iteratively or incrementally.
The error checker can determine the expected change based on geometric calculations of hydrostatic pressure, for example using the relationship of Eq. 1. The error checker can determine the expected change based additionally on the direction of gravity at the strain gauge, where hydrostatic pressure is a function of normal forces which change for non-vertical wells. In some examples, the expected change in hydrostatic pressure can be negative, such as for wellbores which trend upwards (i.e., against gravity) in lateral legs. The error checker can determine the expected change based on one or more wellbore model. The error checker can determine the expected change as a measure of pressure (e.g., in lbs per unit area), as a measure of strain (e.g., in mV/V), or in any other appropriate unit. For example, the error checker can calculate the expected change in the hydrostatic pressure as a pressure and then convert the expected change in the hydrostatic pressure to an expected change in the hydrostatic pressure-effect offset based on a relationship between strain measurements or strain responses for a strain gauge and pressure.
At block 428, the error checker optionally determines an expected change in the hydrostatic pressure-effect offset based on a change in mud weight. Mud weight can encompass various fluid pressure, such as mass, density, etc. The error checker can determine an expected change based on changes in additional mud properties, such as viscosity, diffusivity, etc. The error checker can determine if the mud weight (or another fluid property) has changed and if the mud weight has not changed, determine that the expected change is zero or negligible. If error checker determines that the mud weight has changed, the error checker can then output an expected change in the hydrostatic pressure-effect based on the determined mud weight change. A change in mud weight can be detected by another program or controller, such as identified by a mud pump or operator at the surface, and transmitted to the error checker. The error checker can determine if the mud weight has changed based on an average mud weight or other composite value for the wellbore or wellbore operation. The error checker can determine that the mud weight has changed based on an influx of formation fluid into the wellbore or based on an outflow of drilling mud to the formation. The error checker can determine that the mud weight has changed based on presence or absence of drilling cuttings, gas entrapment, etc.
A change in mud weight can be determined based on one or more sensor measurement or data from one or more tool, including logging while drilling (LWD) and measurement while drilling (MWD) tools. The error checker can determine the expected change based on the mud weight for a drilling run or portion of a drilling run. That is, the error checker can determine the expected change based on the cumulative mud weight. The error checker can determine the expected change based on a difference in the mud weight for the detected stand and a location associated with the previously determined hydrostatic pressure-effect offset value. That is, the error checker can determine the expected change iteratively or incrementally. The expected change in hydrostatic pressure can be positive or negative based on the direction of the change in mud weight. The error checker can determine the expected change based on one or more wellbore and/or mud weight model. The error checker can determine the expected change as a measure of pressure (e.g., in lbs per unit area), as a measure of strain (e.g., in mV/V), or in any other appropriate unit. For example, the error checker can calculate the expected change as a pressure and then convert the expected change in the hydrostatic pressure to an expected change in the hydrostatic pressure-effect offset based on a relationship between strain measurements or strain responses for a strain gauge and pressure.
At block 440, the error checker determines if the change in the hydrostatic pressure-effect offset value conforms to expected trend(s). The error checker can determine whether or not the determined change in the hydrostatic pressure-effect offset value conforms to one or more expected trend, where the expected trends can include at least one of: (1) substantial stability between subsequent stands, (2) increase in pressure-effect offset due to depth, and/or (3) proportionality with mud weight changes. The error checker can determine if the change in the hydrostatic pressure-effect offset is generally stable between stands and during stand additions. For example, if the off-bottom, no fluid flow portion of the stand addition takes five (5) minutes, the error checker can determine if the hydrostatic pressure-effect offset value drifts or changes during that time. In another example, the error checker can determine if the value of the hydrostatic pressure-effect offset changes by less than a threshold between subsequent or sequential stand additions. The threshold can instead be a range of values. The error checker can also determine if the change in the hydrostatic pressure-effect offset is generally stable over a drilling run, such as for each stand addition or a portion of the stand additions of a drilling run. Stable in this case can mean stable to within a margin of error or threshold. The error checker can also determine that the change in the pressure-effect offset generally conforms to a trend, such as increasing linearly, increasing sub-linearly, increasing exponentially, etc. The error checker can then determine if the change in the hydrostatic pressure-effect offset value for the detected stand addition conforms to the pattern of other hydrostatic pressure-effect offset values. The error checker can identify or fit a pattern in the hydrostatic pressure-effect offset values or the change in the hydrostatic pressure-effect offset values. The error checker can determine if the hydrostatic pressure-effect offset conforms to the expected trend(s) based on machine learning.
The error checker can also determine if the change in the hydrostatic pressure-effect offset conforms to the expected change determined based on the wellbore trajectory (in block 426) and/or the expected change determined based on the change in mud weight (in block 428). If the error checker determines that the change in the hydrostatic pressure-effect offset conforms to expected trend(s), flow continues to block 444. If the error checker determines that the change in the hydrostatic pressure-effect offset does not conform to expected trend(s), flow continues optionally to block 442 or to block 446.
At block 442, the error checker optionally determines if the change in the hydrostatic pressure-effect offset value indicates unexpected wellbore conditions. The error checker can attempt to determine if the hydrostatic pressure-effect offset value is a result of an error in the strain measurements or an unexpected event in the wellbore. An unexpected change in hydrostatic pressure can be caused by an unexpected change in mud weight, an unexpected wellbore trajectory (such as unexpected depth, inclination, etc.), an unexpected influx or outflow into the wellbore, etc. An unexpected change in the hydrostatic pressure-effect offset can therefore be a result of a real but unexpected wellbore condition or event and can be used to detect these conditions and events. The error checker can trigger a warning to the operator or a controller of the wellbore operation that an unexpected hydrostatic pressure-effect offset is determined.
The error checker can also determine if the change in the hydrostatic pressure-effect offset indicates unexpected wellbore conditions based on multiple hydrostatic pressure-effect offset values and/or values for multiple stand additions. For example, the error checker can determine that a single hydrostatic pressure-effect offset value which does not conform to an expected trend is erroneous but then determine, based on multiple hydrostatic pressure-effect offset values which do not conform or even indicated a new or different trend is occurring, determine that the change indicates an unexpected wellbore condition. The error checker can determine if the change indicated unexpected wellbore conditions based on a threshold number of hydrostatic pressure-effect offset values or a threshold change in the hydrostatic pressure-effect offset value. For example, the error checker can determine that the hydrostatic pressure-effect offset value is increasing at a first value per stand addition for a first portion of the wellbore and then determine that the hydrostatic pressure-effect offset value is increasing at a second value per stand addition for a second portion of the wellbore. The error checker can implement various control methods, such as standard deviation monitoring (i.e., six sigma) and the like, to detect and predict changes in the hydrostatic pressure-effect offset and trends in changes in the hydrostatic pressure-effect offset. If the error checker determines that the change in the hydrostatic pressure-effect offset indicates unexpected wellbore conditions, flow continues to block 444. If the error checker determines that the change in the hydrostatic pressure-effect offset does not indicate unexpected wellbore conditions, flow continues to block 446.
At block 444, the error checker outputs the hydrostatic pressure-effect offset value for the current stand for strain measurement determination. The error checker can output the hydrostatic pressure-effect offset value to a strain measurement zeroing system or controller, to a pressure calculator, to a WOB calculator, etc. The error checker can output the hydrostatic pressure-effect offset value to storage or memory or append the hydrostatic pressure-effect offset to strain measurement data sets, where it can be accessed by any program accessing the strain measurements. The error checker can also subtract the hydrostatic pressure-effect offset from the strain measurements and output a set of strain measurements which have been zeroed or tared to account for the hydrostatic pressure-effect offset.
At block 446, the error checker determines that the hydrostatic pressure-effect offset for the current stand is erroneous and outputs the previously determined hydrostatic pressure-effect offset value for strain measurement determination. The error checker can discard the erroneous hydrostatic pressure-effect offset, or can report or store the erroneous hydrostatic pressure-effect offset such as for error analysis and analysis of trends in the hydrostatic pressure-effect offset. For example, the error checker can determine that a first hydrostatic pressure-effect offset value is erroneous, but then based on at least a second hydrostatic pressure-effect offset value determine that the first value was not erroneous but instead indicated an unexpected wellbore condition and can recalculate or cause to be recalculated various strain measurements using the first value which was previously marked as erroneous.
The error checker can output the previously determined hydrostatic pressure-effect offset value to a strain measurement zeroing system or controller, to a pressure calculator, to a WOB calculator, etc. The error checker can output the previously hydrostatic pressure-effect offset value to storage or memory or append the previously determined hydrostatic pressure-effect offset to strain measurement data sets, where it can be accessed by any program accessing the strain measurements. The error checker can also subtract the previously determined hydrostatic pressure-effect offset from the strain measurements and output a set of strain measurements which have been zeroed or tared to account for the hydrostatic pressure-effect offset.
At block 448, the error checker determines if an additional stand is detected. The error checker can also detect an additional stand based on an additional trigger from the pressure-effect offset calculator or based on receipt of an additional strain measurements. If an additional stand is detected, flow continues to block 410 where the error checker determines a hydrostatic pressure-effect offset for the detected stand.
At block 502, the error checker detects a stand addition for a drillstring in a wellbore.
At block 510, the error checker determines a hydrodynamic pressure-effect offset value for the detected stand. As previously described with reference to
At block 524, the error checker determines a change in the hydrodynamic pressure-effect offset value based on a difference between the hydrostatic pressure-effect offset value for the detected stand and at least a previously determined hydrostatic pressure-effect offset value. The error checker can determine the change in the hydrodynamic pressure-effect offset using any method appropriate for determining the hydrostatic pressure-effect offset, such as those described in reference to block 410.
At block 530, the error checker optionally determines an expected change in the hydrodynamic pressure-effect offset based on a change in mud weight and/or flow rate. Hydrodynamic pressure is a function of both mud weight and flow rate, but not of depth. The error checker can determine the expected change in the hydrodynamic pressure-effect based on the change in mud weight using any method appropriate for determining the expected change in the hydrostatic pressure-effect offset due to a change in mud weight, such as those described in reference to block 428.
The error checker can determine if the flow rate has changed and if the flow rate has not changed, determine that the expected change is zero or negligible. If error checker determines that the flow rate has changed, the error checker can then output an expected change in the hydrodynamic pressure-effect based on the determined change. A change in flow rate can be detected by another program or controller, such as identified by a flow monitor or operator at the surface, and transmitted to the error checker. The error checker can determine if the flow rate has changed based on an average flow rate or other composite value for the wellbore or wellbore operation.
Changes in mud weight and flow rate can be additive or subtractive, as the hydrodynamic pressure depends on a number of fluid factors (e.g., density, viscosity, diffusivity, etc.) and fluid flow rates. Changes in mud weight and flow rate can be offsetting—i.e., the expected change in the hydrodynamic pressure-effect offset for an example change in mud weight and a concurrent example change in flow rate can be zero (or negligible), positive, or negative. The error checker can determine the expected change based on the change in mud weight and/or the change in flow rate for a drilling run or portion of a drilling run. That is, the error checker can determine the expected change based on the cumulative mud weight and/or flow rate. The error checker can determine the expected change based on a difference in the mud weight and/or flow rate for the detected stand and a location associated with the previously determined hydrostatic pressure-effect offset value. That is, the error checker can determine the expected change iteratively or incrementally. The expected change in hydrodynamic pressure can be positive or negative based on the direction of the change in mud weight and/or flow rate. The error checker can determine the expected change based on one or more wellbore, mud weight, and flow rate model. The error checker can determine the expected change as a measure of pressure (e.g., in lbs per unit area), as a measure of strain (e.g., in mV/V), or in any other appropriate unit. For example, the error checker can calculate the expected change as a pressure and then convert the expected change in the hydrodynamic pressure to an expected change in the hydrodynamic pressure-effect offset based on a relationship between strain measurements or strain responses for a strain gauge and pressure.
At block 540, the error checker determines if the change in the hydrodynamic pressure-effect offset value conforms to expected trend(s). The error checker can determine whether or not the determined change in the hydrodynamic pressure-effect offset value conforms to one or more expected trend, where the expected trends can include at least one of: (1) substantial stability between subsequent stands, (2) increase in pressure-effect offset due to increase in flow rate, and/or (3) increase in pressure-effect offset due to increase in mud weight. The error checker can determine if the change in the hydrodynamic pressure-effect offset is generally stable between stands and during stand additions. Hydrodynamic pressure, when controlling for mud weight and flow rate, is independent of depth and should remain stable between stands and stand additions. For example, if the off-bottom, fluid flowing portion of the stand addition takes two (2) minutes, the error checker can determine if the hydrodynamic pressure-effect offset value drifts or changes during that time. In another example, the error checker can determine if the value of the hydrodynamic pressure-effect offset changes by less than a threshold between subsequent or sequential stand additions. The threshold can instead be a range of values. The error checker can also determine if the change in the hydrodynamic pressure-effect offset is generally stable over a drilling run, such as for each stand addition or a portion of the stand additions of a drilling run. Stable in this case can mean stable to within a margin of error or threshold. The error checker can determine if the hydrostatic pressure-effect offset conforms to the expected trend(s) based on machine learning.
The error checker can also determine if the change in the hydrodynamic pressure-effect offset conforms to expected change determined based on the change in mud weight and/or flow rate (in block 530). If the error checker determines that the change in the hydrodynamic pressure-effect offset conforms to expected trend(s), flow continues to block 544. If the error checker determines that the change in the hydrodynamic pressure-effect offset does not conform to expected trend(s), flow continues optionally to block 544 or to block 546.
At block 542, the error checker optionally determines if the change in the hydrodynamic pressure-effect offset value indicates unexpected wellbore conditions. The error checker can determine if the change in the hydrodynamic pressure-effect offset value indicates unexpected wellbore conditions using any method appropriate for determining if the change in the hydrostatic pressure-effect offset value indicated unexpected wellbore conditions, such as those described in reference to block 442. If the error checker determines that the change in the hydrodynamic pressure-effect offset indicates unexpected wellbore conditions, flow continues to block 544. If the error checker determines that the change in the hydrodynamic pressure-effect offset does not indicate unexpected wellbore conditions, flow continues to block 546.
At block 544, the error checker outputs the hydrodynamic pressure-effect offset value for the current stand for strain measurement determination. The error checker can output the hydrodynamic pressure-effect offset value using any method appropriate for outputting the hydrostatic pressure-effect offset value, such as those described in reference to block 444.
At block 546, the error checker determines that the hydrodynamic pressure-effect offset for the current stand is erroneous and outputs the previously determined hydrodynamic pressure-effect offset value for strain measurement determination. The error checker can determine that the hydrodynamic pressure-effect offset is erroneous and output the previously determined hydrodynamic pressure-effect offset value using any method appropriate for determining the hydrostatic pressure-effect offset is erroneous and outputting the previously determined hydrostatic pressure-effect offset, such as those described in reference to block 446.
At block 548, the error checker determines if an additional stand is detected. If an additional stand is detected, flow continues to block 510 where the error checker determines a hydrostatic pressure-effect offset for the detected stand.
The flowcharts are provided to aid in understanding the illustrations and are not to be used to limit scope of the claims. The flowcharts depict example operations that can vary within the scope of the claims. Additional operations may be performed; fewer operations may be performed; the operations may be performed in parallel; and the operations may be performed in a different order. For example, the operations depicted in blocks 426 and 428 can be performed in parallel or concurrently. With respect to
During the time period covered by an arrow 610, the drillstring is in the off-bottom, no fluid flow portion of the stand addition. The arrow 610 identifies values of WOB that are substantially zero, where the WOB values have been tared to remove hydrostatic pressure from the WOB measurements. During the time period covered by an arrow 612, the drillstring is in the off-bottom, fluid flowing portion of the stand addition. The arrow 612 identifies values of WOB that are relatively steady, except for a peak 614. The graph 600 displays WOB values which have been tared to remove the hydrostatic pressure (e.g., WOB measurements corresponding to the arrow 610) and therefore displays increases in pressure from the hydrostatic pressure during subsequent time periods (i.e., time periods after those identified by the arrow 610). The peak 614 represents an increase in WOB measurements due to a contribution from hydrodynamic pressure. The decrease in the peak 614 is a function of stabilization of WOB which occurs after a surge due to the initial fluid flow as the pumps turn on. The arrow 612 identifies values that have been incompletely zeroed to remove hydrodynamic pressure from the WOB measurements, where the values are not substantially zero due to incomplete taring of values. The WOB values are instead represented by an arrow 616, which corresponds to the WOB contribution from hydrodynamic pressure after the contribution from hydrostatic pressure is removed.
A dashed line 617 represents the time at which fluid flow begins, and which separates the hydrostatic regime of the arrow 610 form the hydrostatic-and-hydrodynamic regime of the arrow 612. A dashed line 618 represents the time at which the drill bit is brought back into contact with the bottom of the wellbore (e.g., pick up of WOB). The line 606 increases as WOB is added back onto the drillstring, until at a time period identified by an arrow 620 the WOB on the drillstring reaches a steady state.
During the time period covered by an arrow 640, the drillstring is in the off-bottom, no fluid flow portion of the stand addition. The arrow 640 identifies values of TOB that correspond to a local minimum, where fluid is not flowing and the drill bit and/or mud motor are not rotating and not creating torque on the bit. During the time period covered by an arrow 642, the drillstring is in the off-bottom, fluid flowing portion of the stand addition. The arrow 642 identifies values of TOB that are relatively steady, except for a peak indicated by an arrow 644. The peak at the arrow 644 represents an increase in TOB measurements due to a touchdown of the drill bit as it is brough back into contact with the wellbore bottom. The arrow 646 represents an increase in TOB between the off-bottom, no fluid flow and off-bottom, fluid flowing portions of the stand addition.
A dashed line 647 represents the time at which fluid flow begins, and which separates the hydrostatic regime of the arrow 640 form the hydrostatic-and-hydrodynamic regime of the arrow 642. A dashed line 648 represents the time at which the drill bit is brought back into contact with the bottom of the wellbore, or pick up of WOB. After the drillstring comes back into contact with the bottom (during the time period covered by an arrow 650), the TOB increases to a value indicated by the arrow 644 and then increases substantially to return to a steady state value for drilling (e.g., the steady state value indicated by an arrow 650). It should be understood that the values indicated by the arrow 644 and the arrow 650 are different enough (such that the value indicated by the arrow 650 is much larger than the value indicated by the arrow 644 and can be orders of magnitude larger) that they are separated by a break 633 in the y-axis corresponding to TOB in order to allows such values to be plotted on a single graph while preserving the information contained in the TOB for off-bottom portions of the stand addition.
During the time period covered by an arrow 670, the drillstring is in the off-bottom, no fluid flow portion of the stand addition. The arrow 670 identifies values of RPM that are substantially zero. During the time period covered by an arrow 672, the drillstring is in the off-bottom, fluid flowing portion of the stand addition. The arrow 672 identifies values of RPM that are relatively steady about an RPM value represented by an arrow 676, except for peaks 673 and 674. The peak 673 represents an increase in RPM due to ramp up of a drill bit or mud motor as fluid begins to flow through the drillstring. The peak 674 represents an increase in RPM measurements due to touchdown of the drill bit as it is brought back into contact with the wellbore bottom. The peak 674 can also represent a measurement artifact and may not correspond to an actual RPM increase.
A dashed line 682 represents the time at which fluid flow begins, and which separates the hydrostatic regime of the arrow 670 form the hydrostatic-and-hydrodynamic regime of the arrow 672. A dashed line 684 represents the time at which the drill bit is brought back into contact with the bottom of the wellbore, or pick up of WOB. After the drillstring comes back into contact with the bottom, the RPM returns to a steady state value smaller than that off the off-bottom, fluid flowing regime as represented by an arrow 677.
The drilling rig 902 may thus provide support for the drillstring 908. The drillstring 908 may operate to penetrate the rotary table 910 for drilling the borehole 912 through subsurface formations 914. The drillstring 908 may include a kelly 916, drill pipe 918, and a bottom hole assembly 920A or 920B, perhaps located at the lower portion of the drill pipe 918. Both a vertical and lateral portion of the borehole 912 are depicted. It should be understood that drilling can take place at an inclination, including in a lateral borehole that trends upwards. The drillstring 908 may also include one or more centralizers 946 or other standoff devices. The one or more centralizer 946 may make intermittent or consistent contact with the borehole 912 as the drillstring 908 is advanced through the subsurface formations 914.
The bottom hole assembly 920 may include drill collars 922, a down hole tool 924, and a drill bit 926. The drill bit 926 may operate to create a borehole 912 by penetrating the surface 904 and subsurface formations 914. The down hole tool 924 may comprise any of a number of different types of tools including MWD tools, LWD tools, and others.
During drilling operations, the drillstring 908 (perhaps including the Kelly 916, the drill pipe 918, and the bottom hole assembly 920) may be rotated by the rotary table 910. In addition to, or alternatively, the bottom hole assembly 920 may also be rotated by a motor (e.g., a mud motor) that is located down hole. Additionally, the mud motor may be used as a communication device, such as via frequency or amplitude modulation, between the drill bit 926 and surface controller located at the surface 904. The drill collars 922 may be used to add weight to the drill bit 926. The drill collars 922 may also operate to stiffen the bottom hole assembly 920, allowing the bottom hole assembly 920 to transfer the added weight to the drill bit 926, and in turn, to assist the drill bit 926 in penetrating the surface 904 and subsurface formations 914.
During drilling operations, a mud pump 932 may pump drilling fluid (sometimes known by those of ordinary skill in the art as “drilling mud”) from a mud pit 934 through a hose 936 into the drill pipe 918 and down to the drill bit 926. The drilling fluid can flow out from the drill bit 926 and be returned to the surface 904 through an annular area 940 between the drill pipe 918 and the sides of the borehole 912. The drilling fluid may then be returned to the mud pit 934, where such fluid is filtered. In some embodiments, the drilling fluid can be used to cool the drill bit 926, as well as to provide lubrication for the drill bit 926 during drilling operations. Additionally, the drilling fluid may be used to remove subsurface formation 914 cuttings created by operating the drill bit 926.
As will be appreciated, aspects of the disclosure may be embodied as a system, method or program code/instructions stored in one or more machine-readable media. Accordingly, aspects may take the form of hardware, software (including firmware, resident software, micro-code, etc.), or a combination of software and hardware aspects that may all generally be referred to herein as a “circuit,” “module” or “system.” The functionality presented as individual modules/units in the example illustrations can be organized differently in accordance with any one of platform (operating system and/or hardware), application ecosystem, interfaces, programmer preferences, programming language, administrator preferences, etc.
Any combination of one or more machine readable medium(s) may be utilized. The machine-readable medium may be a machine-readable signal medium or a machine-readable storage medium. A machine-readable storage medium may be, for example, but not limited to, a system, apparatus, or device, that employs any one of or combination of electronic, magnetic, optical, electromagnetic, infrared, or semiconductor technology to store program code. More specific examples (a non-exhaustive list) of the machine-readable storage medium would include the following: a portable computer diskette, a hard disk, a random-access memory (RAM), a read-only memory (ROM), an erasable programmable read-only memory (EPROM or Flash memory), a portable compact disc read-only memory (CD-ROM), an optical storage device, a magnetic storage device, or any suitable combination of the foregoing. In the context of this document, a machine-readable storage medium may be any tangible medium that can contain, or store a program for use by or in connection with an instruction execution system, apparatus, or device. A machine-readable storage medium is not a machine-readable signal medium.
A machine-readable signal medium may include a propagated data signal with machine readable program code embodied therein, for example, in baseband or as part of a carrier wave. Such a propagated signal may take any of a variety of forms, including, but not limited to, electro-magnetic, optical, or any suitable combination thereof. A machine-readable signal medium may be any machine-readable medium that is not a machine-readable storage medium and that can communicate, propagate, or transport a program for use by or in connection with an instruction execution system, apparatus, or device.
Program code embodied on a machine-readable medium may be transmitted using any appropriate medium, including but not limited to wireless, wireline, optical fiber cable, RF, etc., or any suitable combination of the foregoing.
The program code/instructions may also be stored in a machine-readable medium that can direct a machine to function in a particular manner, such that the instructions stored in the machine-readable medium produce an article of manufacture including instructions which implement the function/act specified in the flowchart and/or block diagram block or blocks.
While the aspects of the disclosure are described with reference to various implementations and exploitations, it will be understood that these aspects are illustrative and that the scope of the claims is not limited to them. In general, techniques for strain measurement offset or zero-point calculations as described herein may be implemented with facilities consistent with any hardware system or hardware systems. Many variations, modifications, additions, and improvements are possible.
Plural instances may be provided for components, operations or structures described herein as a single instance. Finally, boundaries between various components, operations and data stores are somewhat arbitrary, and particular operations are illustrated in the context of specific illustrative configurations. Other allocations of functionality are envisioned and may fall within the scope of the disclosure. In general, structures and functionality presented as separate components in the example configurations may be implemented as a combined structure or component. Similarly, structures and functionality presented as a single component may be implemented as separate components. These and other variations, modifications, additions, and improvements may fall within the scope of the disclosure.
Embodiment 1: A method comprising: obtaining strain measurements from a strain gauge at a first location associated with a drillstring, based on detection of a pause in drilling; determining an offset value corresponding to a fluid pressure based on the strain measurements, wherein the offset value indicates contribution of fluid pressure to the strain measurements and the fluid pressure comprises at least one of hydrostatic pressure and hydrodynamic pressure; and indicating the offset value for zeroing of the strain measurements.
Embodiment 2: The method of embodiment 1, wherein obtaining strain measurements from a strain gauge further comprises: determining if the drillstring is off bottom; and selecting a subset of the strain measurements corresponding to the drillstring being off bottom, based on a determination that the drill string is off bottom, wherein determining the offset value comprises determining the offset value based on the selected subset of the strain measurements.
Embodiment 3: The method of embodiment 2, wherein determining that the drillstring is off bottom comprises: obtaining weight on bit measurements and torque on bit measurements for a drill bit associated with the drillstring; determining if a local minimum in the weight on bit measurements occurs based on the weight on bit measurements; determining if the torque on bit measurements are substantially equal to zero; and determining that the drillstring is off bottom, based on the determination that there is a local minimum in the weight on bit measurements and that the torque on bit measurements are substantially equal to zero.
Embodiment 4: The method of embodiment 1 or 2, wherein obtaining strain measurements further comprises: determining that drilling fluid is not flowing; and selecting a subset of the strain measurements that correspond to the drilling fluid not flowing, based on a determination that the drilling fluid is not flowing, wherein determining the offset value comprises determining a hydrostatic offset value based on the selected subset of strain measurements.
Embodiment 5: The method of embodiment 4, wherein determining that the drilling fluid is not flowing comprises: obtaining at least one of rotational velocity measurements for a drill bit associated with the drillstring and motor speed measurements for a drilling fluid pump associated with the drillstring; determining if the at least one of the rotational velocity measurements for the drill bit and the motor speed measurements for the drilling fluid pump is substantially equal to zero; and determining that the drilling fluid is not flowing, based on a determination that the at least one of the rotational velocity measurements for the drill bit and the motor speed measurements for the drilling fluid pump is substantially equal to zero.
Embodiment 6: The method of embodiment 1 or 2, wherein obtaining strain measurements from a strain gauge further comprises: determining that drilling fluid is flowing; and selecting a subset of the strain measurements corresponding to the drilling fluid flowing, based on a determination that the drilling fluid is flowing, wherein determining the offset value comprises determining a hydrodynamic offset value based on the selected subset of the strain measurements.
Embodiment 7: The method of embodiment 6, wherein determining that the drilling fluid is flowing comprises: obtaining at least one of rotational velocity measurements for a drill bit associated with the drillstring and motor speed measurements for a drilling fluid pump associated with the drillstring; determining if the at least one of the rotational velocity measurements for the drill bit and the motor speed measurements for the drilling fluid pump is substantially not equal to zero; and determining that the drilling fluid is flowing, based on a determination that the at least one of the rotational velocity measurements for the drill bit and the motor speed measurements for the drilling fluid pump is substantially not equal to zero.
Embodiment 8: The method of any one of embodiments 1 to 7, wherein detection of the pause in drilling comprises at least one of detection of an off-bottom event, detection of a stand addition, and detection of an addition of a drillstring component.
Embodiment 9: The method of any one of embodiments 1 to 8, wherein the strain measurements comprise at least one of axial strain measurements and transverse strain measurements.
Embodiment 10: The method of any one of embodiments 1 to 9, wherein determining an offset value comprises: determining a hydrostatic offset value and a total offset value on the strain measurements; and determining a hydrodynamic offset value based, at least in part, on a difference between the total offset value and the hydrostatic offset value.
Embodiment 11: The method of any one of embodiments 1 to 10, wherein indicating the offset value further comprises: determining if the offset value is erroneous; indicating the offset value for zeroing of the strain measurements, based on a determination that the offset value is not erroneous; and indicating at least one previously determined offset value for zeroing of the strain measurements, based on a determination that the offset value is erroneous.
Embodiment 12: The method of embodiment 11, wherein determining if the offset value is erroneous comprises: determining a difference between the offset value and the at least one previously determined offset value; determining if the difference corresponds to an expected value of the difference between the offset value and the at least one previously determined offset value; determining that the offset value is not erroneous, based on a determination that the difference does correspond to an expected value; and determining that the offset value is erroneous, based on a determination that the difference exceed the expected value.
Embodiment 13: The method of embodiment 12, wherein determining if the difference corresponds to an expected value of the difference further comprises determining the expected value of the difference between the offset value and the at least one previously determined offset value.
Embodiment 14: A non-transitory, machine-readable medium having instructions stored thereon that are executable by a computing device to perform operations comprising instruction to: obtain strain measurements from a strain gauge at a first location associated with a drillstring, based on detection of a pause in drilling; determine an offset value corresponding to a fluid pressure based on the strain measurements, wherein the offset value indicates contribution of fluid pressure to the strain measurements and the fluid pressure comprises at least one of hydrostatic pressure and hydrodynamic pressure; and indicate the offset value for zeroing of the strain measurements.
Embodiment 15: The machine-readable medium of embodiment 14, wherein instructions to obtain strain measurements from a strain gauge comprise instructions to: determine if the drillstring is off bottom; determine that drilling fluid is not flowing; and select a subset of the strain measurements corresponding to the drillstring being off bottom and drilling fluid not flowing, based on a determination that the drill string is off bottom and that drilling fluid is not flowing, wherein instructions to determine the offset value comprises instructions to determine a hydrostatic offset value based on the selected subset of the strain measurements.
Embodiment 16: The machine-readable medium of embodiment 14 or 15, wherein instructions to obtain strain measurements from a strain gauge comprise instruction to: determining if the drillstring is off bottom; determine that drilling fluid is flowing; and selecting a subset of the strain measurements that correspond to the drillstring being off bottom and drilling fluid flowing, based on a determination that the drill string is off bottom and that drilling fluid is flowing, wherein instruction to determining the offset comprises instruction to determine a hydrodynamic offset value based on the selected subset of the strain measurements.
Embodiment 17: The machine-readable medium of any one of embodiments 14 to 16, further comprising instruction to: determine a difference between the offset value and at least one previously determined offset value; determine if the difference corresponds to an expected value of the difference between the offset value and the at least one previously determined offset value; indicate the offset value for zeroing of the strain measurements, based on a determination that the difference does correspond to an expected value; and indicate at least one of the at least one previously determined offset value for zeroing of the strain gauge, based on a determination that the difference exceed the expected value.
Embodiment 18: An apparatus comprising: at least one strain gauge at a first location associated with a drillstring; a processor; and a computer-readable medium having instructions stored thereon that are executable by the processor to cause the apparatus to, obtain strain measurements from the at least one strain gauge, based on detection of a pause in drilling; determine a offset value corresponding to a fluid pressure based on the strain measurements, wherein the offset value indicates contribution of fluid pressure to the strain measurements and the fluid pressure comprises at least one of hydrostatic pressure and hydrodynamic pressure; and indicate the offset value for zeroing of the strain measurements.
Embodiment 19: The apparatus of embodiment 18, wherein the first location is associated with a drill bit of the drillstring.
Embodiment 20: The apparatus of embodiment 18 or 19, further comprising instruction to: determine a difference between the offset value and at least one previously determined offset value; determine if the difference corresponds to an expected value of the difference between the offset value and the at least one previously determined offset value; indicate the offset value for zeroing of the strain measurements, based on a determination that the difference does correspond to an expected value; and indicate at least one of the at least one previously determined offset value for zeroing of the strain gauge, based on a determination that the difference exceed the expected value.
Use of the phrase “at least one of” preceding a list with the conjunction “and” should not be treated as an exclusive list and should not be construed as a list of categories with one item from each category, unless specifically stated otherwise. A clause that recites “at least one of A, B, and C” can be infringed with only one of the listed items, multiple of the listed items, and one or more of the items in the list and another item not listed.
Claims
1. A method comprising:
- obtaining strain measurements from a strain gauge at a first location associated with a drillstring, based on detection of a pause in drilling;
- determining an offset value corresponding to a fluid pressure based on the strain measurements, wherein the offset value indicates contribution of fluid pressure to the strain measurements and the fluid pressure comprises at least one of hydrostatic pressure and hydrodynamic pressure; and
- indicating the offset value for zeroing of the strain measurements.
2. The method of claim 1, wherein obtaining strain measurements from a strain gauge further comprises:
- determining if the drillstring is off bottom; and
- selecting a subset of the strain measurements corresponding to the drillstring being off bottom, based on a determination that the drill string is off bottom,
- wherein determining the offset value comprises determining the offset value based on the selected subset of the strain measurements.
3. The method of claim 2, wherein determining that the drillstring is off bottom comprises:
- obtaining weight on bit measurements and torque on bit measurements for a drill bit associated with the drillstring;
- determining if a local minimum in the weight on bit measurements occurs based on the weight on bit measurements;
- determining if the torque on bit measurements are substantially equal to zero; and
- determining that the drillstring is off bottom, based on the determination that there is a local minimum in the weight on bit measurements and that the torque on bit measurements are substantially equal to zero.
4. The method of claim 1, wherein obtaining strain measurements further comprises:
- determining that drilling fluid is not flowing; and
- selecting a subset of the strain measurements that correspond to the drilling fluid not flowing, based on a determination that the drilling fluid is not flowing,
- wherein determining the offset value comprises determining a hydrostatic offset value based on the selected subset of strain measurements.
5. The method of claim 4, wherein determining that the drilling fluid is not flowing comprises:
- obtaining at least one of rotational velocity measurements for a drill bit associated with the drillstring and motor speed measurements for a drilling fluid pump associated with the drillstring;
- determining if the at least one of the rotational velocity measurements for the drill bit and the motor speed measurements for the drilling fluid pump is substantially equal to zero; and
- determining that the drilling fluid is not flowing, based on a determination that the at least one of the rotational velocity measurements for the drill bit and the motor speed measurements for the drilling fluid pump is substantially equal to zero.
6. The method of claim 1, wherein obtaining strain measurements from a strain gauge further comprises:
- determining that drilling fluid is flowing; and
- selecting a subset of the strain measurements corresponding to the drilling fluid flowing, based on a determination that the drilling fluid is flowing,
- wherein determining the offset value comprises determining a hydrodynamic offset value based on the selected subset of the strain measurements.
7. The method of claim 6, wherein determining that the drilling fluid is flowing comprises:
- obtaining at least one of rotational velocity measurements for a drill bit associated with the drillstring and motor speed measurements for a drilling fluid pump associated with the drillstring;
- determining if the at least one of the rotational velocity measurements for the drill bit and the motor speed measurements for the drilling fluid pump is substantially not equal to zero; and
- determining that the drilling fluid is flowing, based on a determination that the at least one of the rotational velocity measurements for the drill bit and the motor speed measurements for the drilling fluid pump is substantially not equal to zero.
8. The method of claim 1, wherein detection of the pause in drilling comprises at least one of detection of an off-bottom event, detection of a stand addition, and detection of an addition of a drillstring component.
9. The method of claim 1, wherein the strain measurements comprise at least one of axial strain measurements and transverse strain measurements.
10. The method of claim 1, wherein determining an offset value comprises:
- determining a hydrostatic offset value and a total offset value on the strain measurements; and
- determining a hydrodynamic offset value based, at least in part, on a difference between the total offset value and the hydrostatic offset value.
11. The method of claim 1, wherein indicating the offset value further comprises:
- determining if the offset value is erroneous;
- indicating the offset value for zeroing of the strain measurements, based on a determination that the offset value is not erroneous; and
- indicating at least one previously determined offset value for zeroing of the strain measurements, based on a determination that the offset value is erroneous.
12. The method of claim 11, wherein determining if the offset value is erroneous comprises:
- determining a difference between the offset value and the at least one previously determined offset value;
- determining if the difference corresponds to an expected value of the difference between the offset value and the at least one previously determined offset value;
- determining that the offset value is not erroneous, based on a determination that the difference does correspond to an expected value; and
- determining that the offset value is erroneous, based on a determination that the difference exceed the expected value.
13. The method of claim 12, wherein determining if the difference corresponds to an expected value of the difference further comprises determining the expected value of the difference between the offset value and the at least one previously determined offset value.
14. A non-transitory, machine-readable medium having instructions stored thereon that are executable by a computing device to perform operations comprising instruction to:
- obtain strain measurements from a strain gauge at a first location associated with a drillstring, based on detection of a pause in drilling;
- determine an offset value corresponding to a fluid pressure based on the strain measurements, wherein the offset value indicates contribution of fluid pressure to the strain measurements and the fluid pressure comprises at least one of hydrostatic pressure and hydrodynamic pressure; and
- indicate the offset value for zeroing of the strain measurements.
15. The machine-readable medium of claim 14, wherein instructions to obtain strain measurements from a strain gauge comprise instructions to:
- determine if the drillstring is off bottom;
- determine that drilling fluid is not flowing; and
- select a subset of the strain measurements corresponding to the drillstring being off bottom and drilling fluid not flowing, based on a determination that the drill string is off bottom and that drilling fluid is not flowing,
- wherein instructions to determine the offset value comprises instructions to determine a hydrostatic offset value based on the selected subset of the strain measurements.
16. The machine-readable medium of claim 14, wherein instructions to obtain strain measurements from a strain gauge comprise instruction to:
- determining if the drillstring is off bottom;
- determine that drilling fluid is flowing; and
- selecting a subset of the strain measurements that correspond to the drillstring being off bottom and drilling fluid flowing, based on a determination that the drill string is off bottom and that drilling fluid is flowing,
- wherein instruction to determining the offset comprises instruction to determine a hydrodynamic offset value based on the selected subset of the strain measurements.
17. The machine-readable medium of claim 14, further comprising instruction to:
- determine a difference between the offset value and at least one previously determined offset value;
- determine if the difference corresponds to an expected value of the difference between the offset value and the at least one previously determined offset value;
- indicate the offset value for zeroing of the strain measurements, based on a determination that the difference does correspond to an expected value; and
- indicate at least one of the at least one previously determined offset value for zeroing of the strain gauge, based on a determination that the difference exceed the expected value.
18. An apparatus comprising:
- at least one strain gauge at a first location associated with a drillstring;
- a processor; and
- a computer-readable medium having instructions stored thereon that are executable by the processor to cause the apparatus to, obtain strain measurements from the at least one strain gauge, based on detection of a pause in drilling; determine a offset value corresponding to a fluid pressure based on the strain measurements, wherein the offset value indicates contribution of fluid pressure to the strain measurements and the fluid pressure comprises at least one of hydrostatic pressure and hydrodynamic pressure; and indicate the offset value for zeroing of the strain measurements.
19. The apparatus of claim 18, wherein the first location is associated with a drill bit of the drillstring.
20. The apparatus of claim 18, further comprising instruction to:
- determine a difference between the offset value and at least one previously determined offset value;
- determine if the difference corresponds to an expected value of the difference between the offset value and the at least one previously determined offset value;
- indicate the offset value for zeroing of the strain measurements, based on a determination that the difference does correspond to an expected value; and
- indicate at least one of the at least one previously determined offset value for zeroing of the strain gauge, based on a determination that the difference exceed the expected value.
Type: Application
Filed: Oct 6, 2021
Publication Date: Apr 6, 2023
Inventors: Bradley David Dunbar (The Woodlands, TX), Van Jordan Brackin (Spring, TX), Paul Gerard Cairns (Houston, TX)
Application Number: 17/450,152
