METHOD AND SYSTEM FOR OPTIMIZING WEIGHT MEASUREMENTS IN DRILLING OPERATIONS, AND, MEDIA READABLE BY

专利摘要:
method and system to optimize weight measurements in drilling operations, and, computer-readable media. systems and methods for automatic calibration of the weight sensor in the drill and bending regulation by buckling of a drill column are described. one method includes making a first survey record at a first depth in a borehole, the first survey record providing the inclination and azimuth of a drill column at the first depth, measuring a weight on a drill bit at the first depth with a sub sensor arranged in a downhole assembly, the downhole assembly forming part of the drill string and the drill bit being arranged at one end of the drill string, calculate a predicted borehole curvature to a second depth in the borehole, the predicted curvature including a predicted slope and predicted azimuth of the drill column at the second depth, calculate a weight correction value based on the predicted hole curvature, and calibrate the sub sensor with the correction value of Weight.
公开号:BR112014013553B1
申请号:R112014013553-3
申请日:2012-12-28
公开日:2021-03-30
发明作者:Richard T. Hay；Robello Samuel
申请人:Halliburton Energy Services, Inc；
IPC主号:

专利说明:

BACKGROUND OF THE INVENTION
[0001] The present description refers to measurement techniques during drilling and, more particularly, to systems and methods for automatic calibration of the weight sensor in the drill and bending regulation by buckling of a drilling column.
[0002] To obtain hydrocarbons such as oil and gas, drillholes are drilled by turning a drill bit attached to one end of the drill string. A large proportion of current drilling activity involves directional drilling; that is, drilling of boreholes deviated and / or horizontal to increase the production of hydrocarbons from underground formations. Modern directional drilling systems generally employ a drill string with a borehole assembly (BHA) and a drill bit located at one end of the drill rig that can be rotated by rotating the drill string from the surface using a motor mud (ie, downhole motor) arranged in the hole below near the drill bit, or a combination of the mud motor and rotation of the drill string from the surface. Pressurized drilling fluid, commonly referred to as "mud" or "drilling mud", is pumped into the drill pipe to cool the drill bit and wash cuttings and particles back to the surface for processing. The mud can also be used to rotate the mud motor and thereby rotate the drill bit.
[0003] The BHA in general includes numerous bore devices below placed in close proximity to the drill bit and configured to measure certain borehole operating parameters associated with the drill string and drill bit. Such devices typically include sensors for measuring temperature and pressure in the hole below, azimuth and inclination measurement devices, and a resistivity measurement device for determining the presence of hydrocarbons and water. Additional subsurface instruments, known as profiling tools during drilling ("LWD") and measurement during drilling ("MWD"), are often attached to the drill string to determine formation geology and formation fluid conditions during drilling operations. drilling.
[0004] Drill holes are usually drilled along predetermined paths and drilling of a typical drill hole continues through various formations. To optimize drilling operations, a surface drilling operator controls the controlled drilling parameters on the surface, such as drill weight, drilling fluid flow through the drill pipe, the rotational speed of the drill string, and the density and drilling fluid viscosity. Downhole operating conditions change continuously and the drilling operator must be able to react to such changes and adjust the controlled parameters on the surface to optimize drilling operations.
[0005] During drilling operations, gravity and curvature of the hole directly impact the drilling performance in terms of precisely determining the true weight that is applied to the drill bit. Without knowing the masking effects created by the gravity and curvature of the hole, it can be extremely difficult to determine whether the weight is being applied to the bottom of the hole correctly. At least one problem encountered is not knowing the true curvature, inclination and azimuth of the hole until after a lifting probe attached to the BHA measures the inclination and azimuth of the hole to a new depth. Until the survey probe reaches that depth, there is a depth delay in the data in knowing just exactly which bend in the hole is at the point of the bottom hole survey measurement. Currently, it is believed that there is no way to know if the true curvature, azimuth and inclination of the hole is below the probe or survey instrument. BRIEF DESCRIPTION OF THE FIGURES
[0006] The following figures are included to illustrate certain aspects of the present description, and should not be seen as inclusive modalities. The subject matter described is liable to considerable modifications, alterations, combinations and equivalents in form and function, as will occur to those skilled in the art and with the benefit of this description.
[0007] FIG. 1 illustrates a drilling system, according to an embodiment of the description.
[0008] FIG. 2 illustrates an exemplary downhole set, according to one or more embodiments of the present description.
[0009] FIGS. 3A-3D illustrate progressive views of a borehole showing the process to correct weight on the drill using real and predictive calculations, according to one or more modalities.
[0010] FIG. 4 illustrates a schematic flowchart of a method for extrapolating the weight along a drill string based on the bore of the borehole, according to one or more modalities.
[0011] FIG. 5 illustrates a simplified schematic diagram of a system that can be configured to execute the methods described here, according to one or more modalities.
[0012] FIG. 6 illustrates a schematic data acquisition system configured to run software to perform operations, according to one or more modalities. BRIEF DESCRIPTION SUMMARY
[0013] The present description refers to measurement techniques during drilling and, more particularly, to systems and methods for automatic calibration of the weight sensor in the drill and bending regulation by buckling of a drilling column.
[0014] In some modalities, a method for optimizing weight measurements in drilling operations is described. The method may include making a first survey record at a first depth in a borehole, the first survey record providing the inclination and azimuth of a drill column at the first depth, measuring a weight on a drill bit at the first depth with a sub sensor arranged in a downhole assembly, the downhole assembly forming part of the drill string and the drill bit being arranged at one end of the drill string, calculate a predicted borehole curvature in a second depth in the borehole, the predicted curvature including a predicted slope and predicted azimuth of the drill column at the second depth, calculate a weight correction value based on the predicted hole curvature, and calibrate the sub sensor with the correction value of weight.
[0015] In other modalities, a system is described to optimize weight measurements in drilling operations. The system may include a downhole assembly coupled to a drill column extended into a borehole, one or more survey probes arranged in the downhole assembly and configured to make a first survey record at a first depth in the borehole, the first survey record providing tilt and azimuth of the drill column at the first depth, a sub sensor arranged in the well end assembly and configured to measure a weight in the drill bit at the first depth, a system for acquiring data coupled communicatively with one or more survey probes and the sub sensor is capable of receiving and processing the first survey record and the weight in the drill bit, and a corrective model of weight and torque communicatively coupled in the data acquisition system and with one or more processors configured to calculate a predicted borehole curvature at a second depth in the borehole and calculate a weight correction value based on the predicted hole curvature, the weight correction value being used to calibrate the sub sensor.
[0016] The features of this description will be readily apparent to those skilled in the art by reading the description of the following preferred modalities. DETAILED DESCRIPTION OF THE INVENTION
[0017] The present description refers to measurement techniques during drilling and, more particularly, to systems and methods for automatic calibration of the weight sensor in the drill and bending regulation by buckling of a drilling column.
[0018] The modalities described here provide methods for correcting weight measurements based on the estimated projection of the drill calculations to estimate a correction in the applied weight until the true curvature of the hole is known. Once the true curvature of the fi le is known, previously estimated values can be updated to true values, thus updating or otherwise reevaluating previously accepted data that were based only on a predictive model. As can be seen, this can reduce the error of knowing the actual contact force of the drill face. In addition, following the exemplary methods described here, it is possible to automatically correct sensor weight measurements during the process using predictive techniques, thereby reducing the number of times required to interrupt and recalibrate the weight measurement device. As can be seen, this can prove to be advantageous in reducing platform time and cost per foot by not having to recalibrate, but it can also increase drilling efficiency and service life by more effective management of the actual weight applied in making drill bit.
[0019] By calibrating and recalibrating the weight sensor (s) to provide a more accurate weight reading on the drill (WOB), the mechanical efficiency of the drill bit can be more precisely assessed to see the extent to which the drill bit is drilling is operating well. For example, a WOB measurement that is larger than the real WOB can lead an operator to conclude that the drill is going blind or that the rock is harder than it really is. Such conclusions could lead to premature replacement of the drill bit. In contrast, a WOB measurement that is smaller than the true WOB could lead the operator to incorrectly conclude that the rock is softer than in reality. Where WOB is unrecognizable by the operator, a conclusion like this could lead to a damaged or broken borehole assembly, including the drill, damaged or broken bearings and / or a jammed or damaged mud motor. Thus, more precise WOB determinations can improve reliability and allow the operator to stay within operating limits and make better informed decisions within operating limits, particularly when drilling directional wells. In addition, a more precise WOB can be used to improve targeting performance and optimize drilling speeds.
[0020] In addition, a more accurate WOB reading can also be used to optimize drilling in a variety of other ways. For example, the operator can draw more precise conclusions regarding the hole conditions below in order to maintain optimal drilling parameters. In addition, a more accurate WOB reading can be used to recommend or make changes to drilling parameters in traction and automatic drilling systems, with or without operator intervention.
[0021] Systems that employ the exemplary methods described here can be proactive in detecting or predicting drilling problems before the drilling application becomes a finishing or cementing task. In addition, deflections of the drill bit can be more easily detected with the exemplary methods described herein, thereby minimizing or otherwise eliminating expensive side tracks altogether, or worse. The described methods can also evolve to the base for an automatic drilling platform. By eliminating the burden of maintaining drilling parameters in the appropriate ranges of the punch and directional punch, more time is left for human data analysis and better judgment based on better data.
[0022] Referring to FIG. 1, an exemplary drilling system 100 is illustrated, which can be used with respect to one or more embodiments of the present description. Drill holes can be created by drilling the earth 102 using the drilling system 100. The drilling system 100 can be configured to drive a downhole assembly (BHA) 104 positioned or otherwise arranged at the bottom of a drilling column. 106 extended on land 102 from a drilling tower 108 arranged on the surface 110. The drilling tower 108 includes a kelly 112 used to lower and raise the drill column 106.
[0023] BHA 104 can include a drill bit 114 and a tool column 116 that can move axially within a well hole drill 118 attached to drill column 106. During operation, drill bit 114 can be provided with sufficient weight on the drill (WOB) and torque on the drill (TOB) from the surface 110 in order to penetrate the earth 102 and thereby create the well hole 118.0 BHA 104 can also provide directional control of the drill bit 114 as it advances on land 102. Tool column 116 can be mounted semi-permanently with various measuring tools (not shown) such as, but not limited to, measurement tools during drilling (MWD) and profiling during drilling (LWD) , which can be configured to take hole measurements below drilling conditions. In other embodiments, the measuring tools can be self-contained in the tool column 116, as shown in FIG. 1.
[0024] Fluid or "sludge" from a sludge tank 120 can be pumped into the bore below using a sludge pump 122 that can be driven by an adjacent power source, such as a driving machine or engine 124. The sludge can be pumped from the mud tank 120, through a vertical mud distribution pipe 126, which feeds the mud into the drill column 106 and transfers it to the drill bit 114. The mud comes out of one or more nozzles arranged in the drill bit drilling 114 and in the process cools the drill bit 114. After exiting the drill bit 114, the mud circulates back to surface 110 via the annular ring defined between the well bore 118 and the drill column 106, and in the process takes gravel and drilling waste, such as sand and shale, to the surface. The gravel and mud mixture passes through a flow line 128 and into an optional agitator or centrifuge (not shown), which separates most solids, such as gravel and fines, from the mud, and takes up the clean mud down into the hole through the vertical mud distribution pipe 126 again. Changes in the various drilling parameters, such as change in the rate of penetration (ROP) in land 102, can be observed, analyzed and taken into account during this process.
[0025] Although the drilling system 100 is shown and described with respect to a rotary drilling system in figure 1, those skilled in the art will easily realize that many types of drilling systems can be employed in carrying out the description modalities. For example, drills and drilling platforms used in the description modalities can be used on land (as shown in figure 1) or offshore (not shown). Offshore oil platforms that can be used according to the modalities of the description include, for example, floats, fixed platforms, gravity-based structures, drill ships, semi-submersible platforms, self-elevating drilling platforms, tension leg platforms and the like. It is clear that the description modalities can be applied on platforms ranging from anything from a small and portable size to bulky and permanent.
[0026] Additionally, although described here with respect to oil drilling, several modalities of the description can be used in many other applications. For example, described methods can be used in drilling for mineral exploration, environmental research, natural gas extraction, underground installation, mining operations, artesian wells, geothermal wells and the like. In addition, description modalities can be used in weight sets in shutters, in descending coating hangers, in descending completion columns, etc., without departing from the scope of the description.
[0027] Referring now to figure 2, continuing with reference to figure 1, an exemplary downhole set (BHA) 104 is illustrated which can be used in relation to one or more modalities of the present description. Although fully described in relation to a BHA, the modalities described here can be alternatively or additionally applied at multiple locations throughout an entire drilling column, and therefore are not limited to the generalized location of a conventional BHA (that is, the bottom of a column of drilling). As shown, the BHA 104 can include the drill bit 114, a rotary blast tool 202, a MWD / LWD 204 tool, and a drill collar 206.
[0028] The MWD / LWD 204 tool may include a MWD sensor package that may include one or more survey probes 207 configured to collect and transmit directional information, mechanical information, training information and the like. In particular, one or more survey probes 207 may include one or more internal or external sensors such as, but without limitation, an inclinometer, one or more magnetometers, (i.e., compass units), one or more accelerometers, a sensor axis position, combinations of these and the like. The distance between the lifting probes 207 and the drill bit 114 can be any axial length required for the particular well drilling application. In some embodiments, for example, the distance between survey probes 207 and drill bit 114 can vary from about 45 feet (13.7 meters) to about 100 feet (30.48 meters). Directional information (ie, well drilling path in three-dimensional space) of BHA 104 on earth 102 (FIG. 1), such as slope and azimuth, can be obtained in real time using survey probes 207.
[0029] The MWD / LWD 204 tool can additionally include an LWD sensor package that can include one or more sensors configured to measure formation parameters such as resistivity, porosity, sonic propagation speed, or gamma ray transmissivity. In some embodiments, the MWD and LWD tools, and their related sensor packages, can stay in communication with each other to share data collected with each other. The MWD / LWD 204 tool can be battery powered or generator driven, as is known in the art, and any measurement obtained from the MWD / LWD 204 tool can be processed on surface 110 (FIG. 1) and / or at a location on the hole below.
[0030] Drill collar 206 can be configured to add weight to BHA 104 above drill bit 114 so that there is enough weight in drill bit 114 to drill through the required geological formations. In other embodiments, weight is also applied to the drill bit 114 through the drill column 106 extended from the surface 110, Weight can be added or removed from the drill bit 114 during operation in order to optimize the performance and efficiency of the drill. For example, as described in more detail below, the borehole curvature can be predicted and the weight applied to the drill bit 114 can be optimized to account for drag forces or friction caused by the curvature. As can be seen, higher values of drag forces will be present where the bore of the borehole is more accentuated.
[0031] BHA 104 may additionally include a sub 208 sensor coupled or otherwise forming part of BHA 104. The sub 208 sensor can be configured to monitor various operating parameters in the downhole environment with respect to BHA 104. For example , the sub 208 sensor can be configured to monitor drilling drill 114 operational parameters such as, but not limited to, drill weight (WOB), drill torque (TOB), rotations per minute (RPM) of drill bit 114, bending moment of drill column 106, vibration that potentially affects drill bit 114 and the like. As illustrated, the sub 208 sensor can be arranged up the hole in the MWD / LWD 204 tool and in the drilling collar 206. In other embodiments, however, the sub 208 sensor can be arranged anywhere along the BHA 104 without departing from the scope of the description.
[0032] In some embodiments, the sub 208 sensor may be a commercially available DRILLDOC® tool from Sperry Drilling of Houston, Texas, USA. The DRILLDOC® tool, or another similar type of sub 208 sensor, can be configured to provide real-time weight, torque and bending measurements on an adjacent cutting tool (ie drill bit 114) and / or column drilling 106 to characterize the transfer of energy from the surface to the cutting tool and / or drilling column 106. As can be seen, these measurements help to optimize drilling parameters to maximize performance and minimize transfer of residual energy and vibration.
[0033] BHA 104 may additionally include a bidirectional communications module 210 coupled or otherwise forming part of the drill column 106. Communications module 210 may be communicatively coupled to each of the sub sensor 208 and the MWD / LWD tool 204 (for example, your search probe (s) 207) via one or more communication lines 212 in such a way that the communication module 210 can be configured to send and receive data from the sub sensor 208 and the MWD tool / LWD 204 in real time.
[0034] Communications module 210 can additionally be coupled communicatively to the surface (not shown) via one or more communication lines 214 in such a way that communications module 210 may be able to send and receive data in real time to surface 110 (FIG. 1) during operation. For example, the communications module 210 can be configured to communicate to the surface 110 various borehole operating parameter data acquired via the sub 208 sensor and the MWD / LWD 204 tool. In other embodiments, however, the communications module 210 can communicate with a computerized system (not shown) or similar configured to receive the various data of borehole operating parameters acquired through the sub 208 sensor and the MWD / LWD 204 tool. As you can see, a computerized system like this can be arranged both on the subsurface and on the surface 110.
[0035] Communication lines 212, 214 can be any type of wired telecommunications device or means known to those skilled in the art, such as, but not limited to, electrical wires or cables, fiber optic cables, etc. For example, in some embodiments, a wire drill pipe (not shown) can be used for bidirectional data transmission between surface 110 and communications module 210. Using a wire drill pipe, BHA 104 and the column drill bits 106 may have electrical wires embedded in one or more of their components in such a way that measurements and signals from the MWD / LWD 204 tool and the sub 208 sensor can be ported directly to surface 110 at high data transmission rates. As can be seen, signal wires can be incorporated into conventional profiling electrical cables, flextubo, or thin non-metallic cables, as known in the art, to directly transmit signals to surface 110 for consideration. Alternatively, or in addition, communications module 210 may include or otherwise be a telemetry module used to transmit measurements to surface 110 wirelessly, if desired, using one or more subsurface telemetry techniques including, but not limited to, without limitation, mud pulse, acoustic, electromagnetic frequency, combinations of these and the like.
[0036] Since the sub 208 sensor is not arranged at the bottom of the BHA 104, or axially adjacent to the drill bit 114, changes in the curvature of the hole (for example, inclination and azimuth) can distort the WOB measurement if the sub sensor 208 is not properly calibrated. Furthermore, buoyancy, drag and mud flow can all affect the measurement of the sub 208 sensor, if it is not calibrated. According to the present description, the WOB measured by the sub 208 sensor can be automatically updated or otherwise compensated based, for example, on one or more of mass, hole curvature, friction (for example, drag effects caused by hole curvature and the like), buoyancy, pipe pressure and mud flow, thereby resulting in a more accurate WOB measurement applied to various hole curvatures. This measurement can be observed by removing part of the effects that mask the real force that is being applied to the axial face of the drill bit 114.
[0037] When not properly calibrated, the WOB detected by the sub 208 sensor may not take into account the curvature of the hole and, therefore, may be inaccurate. To reduce the severity of inaccurate readings from an uncalibrated sub sensor 208, frequent bias correction measurements can be made when the curvature of the hole changes or is expected to change. Modalities of the description avoid this need by automatically compensating for sub 208 sensor measurements based on a predicted hole curvature and its resulting drag effects. Thus, the frequency of tare measurements can be greatly reduced, and less "pumping" in data values will be observed when new tare values are introduced. Constant tare measurements can be made "during the process" using the description modalities, while simultaneously drilling or moving the drill column 106. The application of such modalities finally saves time and platform costs by reducing the time spent calibrating the sub 208 sensor in the descent of the drilling, thus optimizing drilling operations.
[0038] According to the exemplary methods described here, WOB measurement data can be automatically processed and otherwise revised during drilling by factoring out the effects of gravity (eg drag or friction effects) resulting from predicted bending of the hole in order to maintain a true weight applied to the drill column 106 and acting on the drill bit 114. While both effects contribute to the measurement of the sub 208 sensor, it is possible to subtract its effects in order to determine what the actual load is being applied to the face of the drill bit 114. Knowing the actual weight being applied to the drill bit, an operator may be able to intelligently determine whether more or less weight needs to be applied to the drill column 106 in order to maintain forces of drilling in an ideal range and thereby maximize the penetration rate. Experienced in the technique, they will easily perceive that measuring such corrective values during the process can prove to be advantageous in providing valuable diagnostic data in the evaluation of general drilling conditions and drilling performance.
[0039] Furthermore, by calibrating the sub 208 sensor to provide a more accurate WOB reading, the mechanical efficiency of drill bit 114 can be more precisely assessed to see how well it is operating. More accurate WOB determinations can improve reliability and allow the operator to stay within operating limits and make better informed decisions, particularly during directional well drilling. In addition, a more accurate WOB measurement can be used to improve targeting performance, optimize drilling speed and minimize cost per foot. A more accurate WOB reading can be used to optimize drilling equally in a variety of other ways. For example, the operator can draw more precise conclusions regarding the hole conditions below in order to maintain optimal drilling parameters. In addition, a more accurate WOB reading can be used to recommend or make changes to drilling parameters in automatic traction and drilling systems, with or without operator intervention.
[0040] The present methods and systems incorporate predictive modeling in an attempt to reduce WOB errors. The method is designed to work with the directional punch, rather than against it, and aims to provide a worst case, best case intuitive, and probably results in the directional punch at any time being made aware of the possible variance encountered. when targeting decisions are made. By understanding the possible variance, the magnitude of critical targeting deviations can be predicted in advance and decisions made to reduce risk, where possible, before targeting becomes a failure, thereby potentially resulting in and requiring significant remediation efforts. .
[0041] Referring now to figures 3A-3D, continuing with reference to figure 2, progressive views of an exemplary borehole 300 are illustrated showing the process for correcting WOB using real and predictive calculations, according to one or more modalities . The interval or zone above the Pi point in the borehole 300 is the zone where weight measurements have been corrected based on definitive survey results recorded by one or more survey probes 207 of the WMD / LWD 204 tool. In Figure 3a, the interval between point P] and point P2 is a stroke length that has been drilled and points Pi and P2 represent survey points providing drillhole data at the beginning and end, respectively, of the stroke length. Surveys of the borehole 300 at each of the points P] and P2 can be made using the survey probes 207, as discussed in general here above. In this way, the survey information between points P | and P2 of the borehole represents actual measurements of the borehole 300 that can be taken into account by the operator on the surface 110 (FIG. 1).
[0042] The interval between point P2 and point P3 can represent an area where the modeling, according to the modalities discussed here, is used to predict the curvature of the hole and its potential effects on WOB, measured by the sub 208 sensor. The distance to the bottom of the BHA 104 from the survey probe is essentially P3 - P2, and this represents the minimum distance that the operator has to move the drill column 106 in order to match the length of the survey probe BHA 104 207 to the bottom of the drill bit 114.
[0043] Point P3 can be determined by calculating a predicted hole curvature for the stroke length between point P2 and point P3. This can be achieved using a variety of projection lifting techniques up to the drill bit it provides or otherwise way calculates a predicted borehole position. In some embodiments, such calculations can be processed using one or more corrective weight and torque models, such as MAXBHA ™, a software program commercially available from Sperry Drilling Services of Houston, Texas, USA. MAXBHA ™ can be stored on non-transitory, computer-readable media containing program instructions configured to be executed by one or more processors in a computer system, and can help well operators improve well placement, drilling performance and tool reliability through real-time modeling of the critical rotational speed and sediment correction of the borehole 300. Versed in the technique, they will easily understand, however, that any other corrective model of known weight and torque can be used, without departing from the scope of the description. The methods described can use such modeling programs as an example of how the predictive method works to predict and otherwise correct WOB (and TOB, in some applications).
[0044] Although there are several methods available to calculate the position of the borehole 300, or the predicted borehole curvature 300, as known and recognized by those skilled in the art, the methods and / or equations for calculating the position of the borehole used here are used for demonstration purposes only, with the understanding that the use of other methods and equations can also be done by those skilled in the art. A set of equations that is generally accepted by those skilled in the art, and that shows the minimum amount of error in calculating the position and curvature of the borehole, is derived from the Minimum curvature method. The minimum curvature method is detailed extensively in S.J. Sawaryn and J.L. Thorogood, "A Compendium of Directional Calculation with base on Minimum Curvature Method", SPE Drilling and Completion, March 2005, p. 24-36 (SPE 84246), whose contents are hereby incorporated by reference in its entirety.
[0045] In this lifting calculation method, the predicted borehole curvature 300 is considered to be an arc or constant curvature, at the distance from the measured depth between lifting stations (ie the stroke length). More often than not, however, the borehole deviation between two lifting stations is not a smooth arc but is instead made up of segments of varying curvature. In this way, calculations of the minimum curvature can be used to represent the interval as an average of 2 minimum curves that allows matching of the 2 different surveys in the depth interval. The basic equations generally accepted for minimum bore of the borehole 300 are as follows:
where Ij is the inclination of the borehole 300 m at the starting point (for example, P2 in figure 3A), I2 is the projected inclination of the borehole 300 at the end point (for example, P3 in figure 3A), A] is the drillhole azimuth 300 at start point (for example, P2 in figure 3 A), A2 is projected azimuth from drillhole 300 at end point (for example, P3 in figure 3 A), AMD is the change in depth measured between points P2 and P3 in the borehole 300, and β is the form factor of the borehole 300a. The referred variables and their respective derivations and use can be better understood with reference to the technical work of SJ Sawaryn and JL Thorogood cited and incorporated by the previous reference.
[0046] Equations 1-3 provide orthogonal displacement of drill bit 114 within drillhole 300 and the projected or predicted position of drill bit 114 therein. The predicted curvature resulting from borehole 300 can be obtained using the following equation:
where K is the predicted curvature; AI is the difference between and I2; ΔA is the difference between A] and A2; and CL is the stroke length (for example, P2 to P3). The model, run by MAXBHA ™, for example, can be configured to provide or otherwise intelligently predict I2 and A2, and described in more detail below.
[0047] Referring to figure 3B, since the predicted hole curvature is determined for the stroke length between P2 and P3, point P2 of figure 3 A can be discarded and drilling can begin towards P3. In particular, point P2 of figure 3A can be made equivalent to a new P], and the drill string can be moved forward along the length of the projected stroke. As shown in figure 3B, P3 is basically the projected bottom of BHA 104 (that is, not necessarily the bottom of the borehole 300), so that, as BHA 104 travels, the distance from P) to P3 increases incrementally. . In other words, P3 slides along with the bottom of BHA 104 as it drills or travels deeper into the borehole 300,
[0048] As the BHA 104 advances through the borehole 300, the MWD / LWD 204 tool and the sub 208 sensor may be making real-time measurements of the borehole parameters 300, such as "true" bore and azimuth of the hole sounding 300 and gross weight measurements. As can be seen, there is no depth delay associated with measured values of weight and torque recovered from the sub 208 sensor, unlike the depth delay observed in survey measurements retrieved from the 207 survey probes. Therefore, the sub 208 sensor can provide some indication of what is happening in the borehole 300 below the sub 208 sensor to the drill bit 114, while the survey probes 207 are only able to measure what they can see in their localized position.
[0049] Once a "true" gross weight measurement is received in conjunction with the "true" hole curvature, the raw data is used to correct the predictive model regarding the targeting of BHA 104, thereby updating predicting what changes in weight measurement are as the drilling progresses.
[0050] Referring to figure 3C, the point at which the BHA 104 arrives at a new point of the lifting station (shown as P3) at the borehole 300 is illustrated. At point P3, a new lifting can be done using the lifting probes 207 and, as a result, a new position P2, described with reference to figure 3A, can be determined. The presented process can then be repeated, and the weight measurement is updated by reprocessing the weight correction values based on the new known curvature of the hole at the new stroke length, as shown in figure 3D.
[0051] Referring now to figure 4, continuing with reference to figures 2 and 3, a flowchart of a method 400 is illustrated to extrapolate the weight along a drilling column based on the bore of the borehole, according to with one or more modalities. As those skilled in the art can see, several variances in the 400 method can occur without departing from the scope of the description. For example, there are several ways to reduce the complexity of Method 400 depending on the desired accuracy. If the effects of certain borehole parameters are minimal or difficult to measure, an operator may prefer to ignore some elements of Method 400 and accept the variance that the resulting omission would present to the system as part of the overall accuracy of the system.
[0052] In some modalities, method 400 may include making a survey that registers the inclination and azimuth of the drilling column 106 at a first point or depth in the borehole 300, as in 402. In at least one embodiment, a survey such as this can be done by one or more survey probes 207 of the MWD / LWD 204 tool and the first point can be representative of P] of figure 3A. Method 400 may additionally include drilling a gap, as in 404. The gap that is drilled can encompass the stroke length between points Pi and P2 of figure 3A. In the new depth P2, method 400 can continue, measuring the depth of the borehole 300 and WOB, as in 406. As previously discussed, WOB can be measured or otherwise obtained using the sub 208 sensor or any other sensor weight known to those skilled in the art.
[0053] In some embodiments, method 400 may additionally include measuring the direction of the drill bit 114 tool face in conjunction with the aggression of the direction of BHA 104 at the new depth, such as at 408. At the new depth point P2, for example, and in view of the newly obtained drillhole measurements 300, as in 406, the operator can know how aggressive the targeting of BHA 104 may need to be to reach a certain destination and therefore may be able to estimate or predict the bore of the borehole in the length of the next stroke (that is, from P2 to P3). Using the rotary steerable tool 202, the face of the drill bit 114 can be adjusted to whatever aggressiveness is required to reach the predetermined destination of P3. Based on such steering aggressiveness, the operator may be able to estimate changes in the inclination or azimuth of the borehole 300 and, therefore, the change in the curvature thereof. As previously described, such predicted borehole curvature 300 can be estimated using the MAXBHA ™ program or any other weight and torque corrective model method known to those skilled in the art. Until BHA 104 actually reaches point P3, the forecast or "consultation" regarding curvature is counted on.
[0054] Method 400 may also include measuring various borehole parameters 300 while BHA 104 advances into borehole 300. For example, method 400 may include measuring torque (TOB) over the course of the interval, as in 410. More particularly, TOB can be measured progressively as BHA 104 advances from point P] to point P3, as shown in figure 3B, and such measurements can be used to update the curvature model. In one or more modalities, as quickly mentioned here, TOB can be measured using the sub 208 sensor. In other modalities, TOB can be measured on the surface with surface mounted torque sensors.
[0055] Method 400 may also include measuring pressure and flow over the interval, as in 412. The flow of the mud through the drill column 106 and its pressure are parameters or variables that can also affect the measurements of the sub 208 sensor. The mud flow can exert a variety of hydraulic forces on the sub 208 sensor, including, for example, fluid frictional force and piston effects. Fluid friction force is caused by the difficulty of the first layer of fluid surrounding the surface of the BHA 104 to move through, or through, the surface roughness. Piston effects of BHA 104, which impact the tension or compression of BHA 104, are caused by a reduction of the cross sectional flow area inside and / or outside the flow path of BHA 104 in the length of the drill column 106 below the sensor sub 208. These hydraulic forces are basically created by the pressure drop through the nozzles on the drill bit 114. However, other components in the BHA 104 can also impact the overall pressure drop of the drilling fluid between the sub 208 sensor and the bottom of the drill. drill bit 114. Outside BHA 104, mud rings, fillings, mud / collapse formation, gravel build-up or other flow restrictive actions create upward compressive forces on BHA 104, while a pressure drop inside the BHA 104 between the sub 208 sensor and the drill bit 104 creates tension or stretching forces on the BHA 104.
[0056] As fluid seeps over the surface of BHA 104, both in the internal and external flow path, the first fluid layer in general is moving slowly, as it is difficult for the fluid to move through the roughness of the surface, and through her. The effects of mud flow on WOB measurement can be estimated by a variety of methods. For example, a direct measurement of flow effects can be made without trying to characterize the properties of the mud, which can be repeated to recalibrate the model when the hole conditions below change. A more sophisticated model, however, can incorporate sludge properties such as changes in friction and pressure drop due to changes in the flow point, plastic viscosity, density, downhole temperature,% solids, etc. Other methods of determining the effects of mud flow include, for example, calculations based on geometries or surface finish.
[0057] In order to make a direct measurement of the effects of the mud flow on the sub 208 sensor, one or more flow measurements can be made using measurement tools such as, for example, flow line sensors or flow flow interfaces mud, and one or more measurements of the sub 208 sensor can be made using the sub 208 sensor itself. The measurements can then be plotted at their respective flow rates, and a curve fitting equation can be extrapolated through the data points. This curve can subsequently be used to calibrate the sub 208 sensor, as previously described, to remove the effects of changes in the mud flow, without requiring a new tare measurement.
[0058] In an alternative embodiment, pipe pressure can be used, instead of mud flow, for similar results, since pipe flow and pressure are interrelated. The process cited with respect to the pipe pressure would be identical, except that pressure measurements would be made at specific flows, and the measured weight would be corrected based on changes in the internal pressure of the pipe, instead of the flow. Pressure measurements can be made, for example, using the MWD / LWD 204 tool, as is generally known in the art.
[0059] As the flow paths are washed or eroded, however, the pressure versus flow relationship can change with a pressure drop at the same flow. Consequently, a model using pipe pressure can be retested during long runs to verify that changes in pressure versus mud flow have not diverged significantly enough to affect the desired accuracy. Additionally, a tube pressure model can be extended to automatically compensate for pressure variance as a function of flow, which can be useful in situations with wear and / or changes in sludge properties. For example, additives that are added to a sludge system in high concentrations can cause drastic changes in circulating pressure. These pressure changes can occur as the additive circulates through the flow path, as mud systems are changed, or properties change as drilling continues. Increases in pressure can also occur due to restriction of the tube.
[0060] In these cases, the pressure drop across the BHA 104 typically has the maximum impact on the z-axis force applied to the sensor as a result of the mud flow. Consequently, a greater or lesser pressure can be observed for the same flow and thus greater or lesser stretching force of the tube, respectively. By changing the model to respond instead to changes in tube pressure near the sensor, however, a more accurate model can be obtained, which is more immune to changes in strength because of changes in the properties of the mud. Exemplary configurations for making measurements for flow and pressure of the tube can be found in patent application by the same owner US serial number 13 / 518,769 entitled "System and Method for Automatic Weight in bit Sensor Calibration", the contents of which are hereby incorporated by reference in its entirety.
[0061] Still referring to FIG. 4, method 400 may additionally include calculating the predicted curvature, inclination and azimuth in the drill bit 114, as in 414. The predicted curvature may encompass the predicted borehole curvature 300 from P2 to P3, as shown in figure 3A. In one or more modalities, a calculation like this can be derived or otherwise determined using the minimum curvature method previously discussed, and implemented using, for example, MAXBHA ™ software or the like. Some parameters that MAXBHA ™, or a similar drillhole predictive program, can take into account include, but are not limited to, the type of rock being drilled, drill bit speed 114, rigidity of BHA 104 (including how many points contact with the borehole wall 300 exist), the bending angle value in BHA 104, combinations thereof, and the like.
[0062] Once the predicted borehole curvature is determined and otherwise recorded, method 400 may include calculating the new correction weight and / or torque value using the predicted borehole curvature, as in 416 In some modalities, the new weight and / or torque values can take into account borehole parameters such as flow, pipe pressure and predictive curvature. In other modalities, the new weight and / or torque values can take into account gravity or drag effects that could also significantly affect the WOB and TOB measurements obtained by the sub 208 sensor.
[0063] In some embodiments, a correction value for dragging effects can be determined using the "true" weight Fg of the mass below the sub 208 sensor, the projected hole inclination In, and friction. In at least one modality, the correction value can be equal to the drag force Fdn, which corresponds to a net axial force applied to the sub 208 sensor as a result of the drag. The drag force Fdn represents the contact force of the BHA 104 with the hole wall below the sub-208 sensor. As you can see, the drag force Fdn will increase as the borehole bore or hole bend predicted poll increases. Consequently, the drag force Fdn is a function of the dynamic friction coefficient and the force applied to the borehole wall, and can be represented by the following equation:
where pdg is the dynamic friction coefficient between the borehole wall and BHA 104, Fg is the gravitational force applied to the mass below the sub 208 sensor in a vertical free hanging position, and In is the slope of the drill bit 114 in a predicted position in the borehole. The dynamic friction coefficient μdg is used in Equation (5), instead of the static friction coefficient, since it will take into account the effects of axial friction while the drill column tube 106 is being moved.
[0064] The pdg dynamic friction coefficient can be determined by a variety of methods. For example, the change in force from static to dynamic can be measured during dragging of drill string 106 to determine the dragging force. For rotary steerable tools, such as the rotary sub-steer 202 of FIG. 2, where flexion can be adjusted, flexion can be set at 0% and the drag test performed on a straight section of the borehole where there is no interference between BHA 104 and the borehole wall. Alternatively, the dynamic friction coefficient due to μdg gravity can be estimated by analyzing travel data from the sub 208 sensor.
[0065] In general, it can be considered that the magnitude of the drag force Fdn is the same in both directions, although it may be different in reality because of discontinuities or repressed diameters (that is, diameters larger than the normal ones used for tool joint connections or to add weight) in the form of BHA 104. Depending on the direction of movement, however, the drag force Fdn can be both positive and negative because of the storage of potential energy through compression or extension of the BHA 104. For the purposes of the description here, however, the drag force Fdn is treated as positive if the movement is in the downward direction, because it is causing the BHA 104 to compress. If the movement is in the upward direction, the drag force Fdn is treated as negative, as it is causing the BHA 104 to stretch. The directionality of the movement of the drill string 106 can be monitored on the surface 110 (FIG. 1) or can be determined by subsurface equipment such as, for example, a depth sensor as part of the MWD / LWD 204 tool.
[0066] Thus, a "true" WOB FWOBn without the drag effects in view of the predicted bending of the hole can be calculated by subtracting the drag force Fdn (here equal to the correction value) from a measured weight Fzn, as it is shown in the following equation:
where Fzn is a WOB measured on the z-axis at the predicted point in the borehole. Thus, the sub 208 sensor can be calibrated using this correction value (here equal to the drag force Fdn).
[0067] The drag force Fdn, taking into account both slope and azimuth of the projected or measured borehole curvature, can be calculated using the following equation:
where Fn is the lateral force or normal force that drill column 106 or BHA 104 applies to the borehole wall as a result of being bent in the borehole curvature. The normal force Fn can be calculated using the following equation:
where Fe is the axial force at the bottom of the drill column section 106 calculated using the buoyancy method, that is, calculation of the effective stress; Wb is the floating weight of the section (Wb = wb SL, where wb is the floating weight per unit length of the drill column section 106 and SL is the length of the drill column section 106), Δα is the change in azimuth in the section length, 0med is the average slope in the section, and Δ0 is the change in the slope in the section length. The sign in front of the term Wb is based on whether the well drilling is building or falling. The tension is working against the weight veto for a construction section and with the weight vector for a drop section of the well profile.
[0068] Method 400 may additionally include revising the weight and / or torque values measured with corresponding correction values, as in 418. In other words, the sub 208 sensor can be recalibrated with the correction values in such a way that the WOB and TOB values measured can be reset to zero and a tare can be applied to weight and torque measurements to substantially remove bending effects from the predicted borehole.
[0069] At this point, the drilling column 106 advanced from P2 to P3, as in figure 3A, and the old P3 becomes a new P2, as in figure 3D. The operator can now have the option of making an additional survey measurement in P3, as in 420. If the operator chooses to deviate from the additional survey, method 400 can resume drilling for an additional interval, as in 404, and the the above-discussed iterative process can be repeated. However, if the operator chooses to do an additional survey, method 400 may include recording new slope and azimuth values at the new depth, as in 422. The distance to the bottom of BHA 104 from survey probe 207 is P3 - P2, as in the 3D figure. This is the minimum distance that the operator has to move the drill column 106 to match the length of the BHA 104 from the lift probe 207 to the bottom of the drill bit 114.
[0070] With the new slope and azimuth values, the true curvature of the borehole 300 between the previous lifting stations can then be calculated, as in 424. With the true curvature determined, the weight correction data and / or torque for the stroke length between previous lifting stations can be reprocessed or otherwise reevaluated, as in 426. In other words, since more accurate data is now available, the predictive corrections applied to the raw weight and torque data can be discarded and reprocessed values applied to the model. Although there are several ways to make this calculation, as recognized by those skilled in the art, at least one way is to correct gravity effects by performing a numerical integration by the sum of discrete depth intervals measured as a function of the axial contribution of weight due to gravitational forces in the BHA 104. Specifically, using interpolation and / or numerical integration in the small segments of the borehole 300, the WOB effects measured by the sub 208 sensor on the borehole curvature can be determined using the minimum curvature method, as described in general previously.
[0071] In some embodiments, this involves calculating an interpolated slope value for points between the lifting stations and then using that slope to calculate the axial weight contribution of BHA 104 to that measured delta depth range. Tilt changes in stroke length can be integrated against either an average weight per unit length of BHA 104 or a more sophisticated model of weight distribution along the length of BHA 104 based on BHA 104 features to arrive at an integrated sum of the net effect because of gravity. Similarly, the bore of the borehole 300 in the stroke length could be used to calculate the friction (i.e., drag effects) that BHA 104 observed because of bending along the stroke length. Previous estimates for this interval used by the predictive model will then be discarded and this updated correction can then be reapplied to the gross weight data measured over the stroke length.
[0072] Using the least curvature method, calculations to determine the slope in each measured delta depth is a simple way to certify the localized slope of the borehole 300 below the last lifting station. In general, the method of minimum curvature makes a generalized average of a smooth slope change in said interval. However, a more accurate method can be to monitor the drill bit 114 tool face and direction intensity in this range and calculate the predicted change in inclination based on the discrete measurements made in the range, as briefly discussed in 408. A method like this it can result in a series of interconnected closed micro curves and / or straight intervals that all add to the final slope value.
[0073] The key to both methods is the assumption that the unknown slope between the last lifting station and the drill bit is predictable within a certain limit error. Making reasonable assumptions as to what error limits are based on historical performance results for BHA 104 and the formation being drilled can give the user a general understanding of how accurate the predicted values can be.
[0074] In some embodiments, the contribution of only a portion of the effects of BHA 104 on weight measurement can be added, rather than the entire range or length of the stroke. In such modalities, additional error can be considered and an error factor can be introduced in the model to take into account uncompensated length. For example, instead of predicting the curvature and its effects on the various drill hole parameters all the way down to the bottom of the drill bit, it is also contemplated here to stop a short distance from the bottom of the drill bit 114 and yet obtain the reasonable forecast value. In this way, it is perceived that the method described 400 is merely a guide to the general process of forecasting, measuring and reassessment, with the understanding that even a partial length correction is supportive to the self-correcting process.
[0075] At this point, method 400 may resume for drilling an additional interval, as in 404, and the above discussed iterative process repeats. It can be seen that the range of complexity of the 400 method can be adjusted with the assumption that the more variables introduced (that is, borehole parameters that are being measured or otherwise taken into account), the more precise can be the curvature prediction.
[0076] Referring now to figure 5, continuing with reference to the previous figures, there is illustrated a simplified schematic diagram of a system 500 that can be configured to execute the methods described here, according to one or more modalities. As illustrated, system 500 can be configured to obtain or otherwise determine a plurality of borehole parameters or measurements 502 using the various sensors and devices of BHA 104 and / or sensors arranged on surface 110 (FIG. 1). For example, the depth can be measured on the surface 110, the inclination and azimuth measurements can be obtained using the lifting probe 207 of the MWD / LWD 204 tool, the measurement of the tool face can be obtained using the lifting probe 207, the aggressiveness of the targeting can be measured with sensors associated with the rotary steer tool 202, the magnitude of the local gravity can be measured with a gravity meter or similar, the pointing of the survey at the bottom of the borehole can be measured with a sensor inclination near the drill, the flow can be measured both on the surface 110 and the hole below, the differential pressure of the pipe can be measured on the hole below with the MWD / LWD 204 tool, the rotation and speed of the pipe can be measured on the surface 110 , the sludge weight, viscosity and sludge temperature profile can each be measured on surface 110, and the bending of BHA 104 can be measured with the sub 208 sensor and / or on the surface and 110. As briefly mentioned earlier, the range of complexity of the methods described here can be adjusted in such a way that the more drillhole parameters that are being measured or otherwise taken into account, the more accurate the prediction will be. resulting curvature.
[0077] The system 500 can additionally include a data acquisition system 504 that can be configured to receive and process the 502 measurements. In some embodiments, the data acquisition system 504 can be arranged at a location on the subsurface, but, in other embodiments, the data acquisition system 504 can be arranged on the surface 110. The two-way communications module 210 of FIG. 2 can be communicatively coupled to the data acquisition system 504 and thereby be able to provide valuable drillhole parameter data and measurements to the data acquisition system 504 from BHA 104. The data acquisition system 504 can be configured for wired or wireless telecommunications and is discussed in more detail below with reference to figure 6.
[0078] System 500 may additionally include a predictive modeling system 506 used to receive and process borehole parameter data and to determine, calculate or otherwise predict borehole position and curvature. In some embodiments, the 506 predictive modeling system may encompass or otherwise include the MAXBHA ™ software program or platform, as previously discussed. In other modalities, however, the 506 predictive modeling system may encompass or include any other suitable software program or platform in modeling the borehole position and curvature.
[0079] In some modalities, the 506 predictive modeling system may include a 508 weight and torque corrective model with one or more processors configured to process incoming data and provide multiple outputs, as discussed below. For example, the corrective weight and torque model 508 can be configured to communicate with the data acquisition system 504 and thereby obtain measurements 502 and update the predictive model using said measurements 502. When any "true" or known, the 506 predictive modeling system can be configured to reevaluate the predictive model and provide a more accurate prediction of the borehole curvature. The corrective weight and torque model 508 can also receive data from a targeting model 510 that can be configured to predict the change in weight and torque of the BHA 104. In determining the expected changes in weight and torque, the targeting model 510 can take into account or otherwise receive data from a BHA 512 model, several well surveys 514, and a model of training effects 516.
[0080] The BHA 512 model can be configured to provide BHA 104 geometry parameters for the targeting model 510 and thereby provide performance data related to it. Well 514 surveys can be obtained in real time and constantly updated as the drilling process progresses. Updated well surveys can either be provided to the targeting model 510 in such a way that the targeting model 510 is constantly updated and reevaluated, or otherwise the well surveys can be directed to the corrective weight and torque model 508 for updating and reassessing the model's parameters in it that way.
[0081] The 516 formation effects model can provide data related to the compressive strength of the rock, the chemical reactivity of the rock, etc., all of which could affect the aggressiveness of targeting. In some embodiments, the formation effects model 516 can obtain information on formation / targeting / survey data from displaced well 518 which may include information recorded or stored about the particular formation or rock being drilled. For example, before directional drills can have run measurements or diagnostics run in the same formation, or a similar rock formation, and several formation parameters can be obtained in this way, such as, but without limitation, probable construction and turnover rates , targeting performance in such formations, formation properties, and the like. In this way, the properties of the well / targeting / data collection of the displaced well 518 may be able to update the formation effects model 516 with such data in such a way that a more accurate representation of the formation / rock being drilled can be provided to the 510 targeting model.
[0082] Using portions of both predictive and true data, the predictive modeling system 506 can be configured to provide a predictive correction of weight 520 and a predictive correction of torque 524. Predictive corrections of weight and torque 520, 524 can take take into account the delay value and can be based on the predicted or actual borehole curvature processed by the 506 predictive modeling system. Once the actual weight and torque are known, or otherwise determined through the various real-time measurements 502, the predictive modeling system 506 can be configured to determine or otherwise calculate a definitive weight correction 522 and a definitive torque correction 526. Combining the predictive and definitive measurements 520-526 provided by the predictive modeling system 506, data consolidated weight and torque values 528, 530 can be derived. In other words, a combination of the predictive and definitive calculations 520-526 can update or otherwise reevaluate the predictive weight and torque measurement in such a way that a more accurate forecast is provided and the predictive model can more accurately represent the effects of gravity and drag effects due to the true and / or predicted curvature of the borehole.
[0083] The exemplary systems and methods described here may also be suitable in determining or otherwise assessing the buckling bending of a drill string, such as drill string 106 of FIGS. 1 and 2. Drill column 106 naturally follows the curvature of the borehole as it progresses through the formation. When it deflects a certain amount, buckling can occur. The dynamics of buckling bending of a drilling column is basically a function of the hole diameter, pipe diameter, and pipe stiffness that is related to the flow point of the column material and its Young's modulus. Buckling bending can eventually lead to the drilling column 106 being screwed, and the screwing may result in the spiraling column 106 spiraling into the borehole, which could potentially blind or jam drilling operations.
[0084] The buckling folding modes are related to at least three phases as the weight in the drill column 106 increases in compression. First, at a minimum applied weight, drill column 106 can rotate like a generally straight tube column with little or no lateral deformation within the borehole. Second, when the applied weight increases, buckling of the drill column 106 can originate and the drill column 106 can start to move sinuously side by side within the borehole. Third, increasing the applied weight further can cause the drill string 106 to "wriggle" around the borehole as it takes on a helical shape.
[0085] According to some modalities, the measurements of the flexion and flexion moment of the drilling column 106, corresponding to the true and / or predicted curvature of the borehole, can be determined in order to detect buckling by buckling. Properly detecting buckling bending in drill column 106 can help prevent column fatigue failures, reduce harmful vibration modes that can lead to tool failures, and optimize weight transfer (i.e. WOB) to drill bit 114. In some embodiments, WOB optimization may include keeping normal and drag forces from drill column 106 minimized in view of the true and predicted bore of the borehole, and thereby maximizing the penetration rate based on the weight contribution.
[0086] Referring again to FIG. 2, the sub 208 sensor can be configured to detect and otherwise measure bending (for example, bending moment in polar magnitude) and bending direction of BHA 104. In other embodiments, corresponding sensors on surface 110 (FIG. 1) , in conjunction with the sub 208 sensor, can be adapted to cooperatively measure the torsion of the drill column 106, and thereby approximate the bending moment. In some embodiments, the direction of bending can be measured in relation to the high side of the borehole (for example, high magnetic side). When the measured flexion and / or flexion moment exceeds a predetermined limit, this can be an indication of buckling bending of the drill string 106.
[0087] Using the method of minimum curvature, as previously discussed, the curvature of the borehole as a function of the depth of the drill column 106 can be determined. Using these calculations, the bending moment of the drill string 106 as a function of depth based on the bore of the borehole can also be determined. In operation, the bending moment of BHA 104 can provide an indication of where BHA 104 is in the borehole with respect to a known or predicted curvature. For example, in borehole areas where measurements of greater bending or bending moment are reported, this may be an indication of the borehole curvature at that location. As such, measurements of bending and bending moment can prove to be advantageous in approaching the general shape of the borehole which, in turn, can also approximate the general shape of the drill column disposed within the borehole.
[0088] If the borehole bend is known or otherwise predicted to arch in a particular direction at a certain point in the borehole, determined by true or predictive measurements, the BHA 104 bending moment detected by the sub 208 sensor must match that particular curvature. However, if the sub 208 sensor detects that drill string 106 and BHA 104 are arching or otherwise bending in a different direction at that particular curvature, this could be an indication that drill string 106 is warping or starting to warp . In this way, the sinuous or helical forms of bending by buckling can be detectable based on the magnitude and direction of the flexion moment, detected by the sub 208 sensor. As can be seen, the severity of the measured flexion moment of BHA 104 can inform an operator whether winding or helical streak is taking place, or is about to take place. When buckling bending is determined, one or more corrective actions can be taken to reverse buckling bending, such as, but without limitation, reducing the WOB applied by the surface 110, reducing the aggressiveness of the steering, and decreasing the rotational speed of the drill column 106.
[0089] Referring now to figure 6, the data from the hole and surface sensors can be processed and / or displayed using a 600 data acquisition system, according to one or more modalities. The data acquisition system 600 can be substantially similar to the data acquisition system 504 of FIG. 5. The processor components that process such data can be in the hole below and / or on the surface 110 (FIG. 1). For example, one or more processors in a hole tool below can process data from the hole below. Alternatively, or in addition, one or more processors, either on the surface 110 and / or at a remote location can process the data. In addition, the processed data can then be numerically and graphically displayed, as further described below.
[0090] The data acquisition system 600 can be configured to run software to perform operations, according to some modalities of the description. The data acquisition system 600 can be representative of several components. For example, data acquisition system 600 may be representative of parts of BHA 104, a local computer at the platform location, a remote computer at the platform location, etc.
[0091] As shown in figure 6, the data acquisition system 600 may include processor (s) 602. The data acquisition system 600 may also include a memory unit 604, processor bus 606, and hub of the data controller. input / output (ICH) 608. The 602 processor (s), memory unit 604, and ICH 608 can be coupled to the 606 processor bus. The 602 processor (s) can include any suitable processor architecture. The data acquisition system 600 can include one, two, three or more processors, any of which can execute a set of instructions according to the modalities of the description.
[0092] The memory unit 604 can store data and / or instructions, and can include any suitable memory, such as a dynamic random access memory (DRAM). The data acquisition system 600 may also include IDE 610 unit (s) and / or other suitable storage devices. A graphics controller 612 controls the display of information on a display device 614, according to some modalities.
[0093] The input / output controller (ICH) hub 608 can provide an interface for I / O devices or peripheral components for the data acquisition system 600. ICH 608 can include any interface controller suitable to provide any connection adequate communication on processor (s) 602, memory unit 604 and / or any suitable device or component in communication with ICH 608. In at least one embodiment of the description, ICH 608 provides adequate arbitration and temporary storage for each interface.
[0094] In some embodiments of the description, ICH 608 may provide an interface for one or more components of suitable integrated programming environment unit (IDE) 610, such as a hard disk drive (HDD) or read-only memory of compact disc (CD ROM), or for suitable universal serial bus (USB) devices via one or more USB 616 ports. In at least one embodiment, the ICH 608 can also provide an interface for a 618 keyboard, a 620 mouse, a CD-ROM drive 624, one or more suitable devices via one or more protection ports 622. In at least one embodiment of the description, the ICH 608 can also provide a network interface 626 through which the 600 data can communicate with other computers and / or devices.
[0095] In some modalities, the data acquisition system 600 may include a non-transitory machine-readable medium that stores a set of instructions (for example, software) incorporating any one, or all of the methodologies and / or processes described here. In addition, software may reside, completely or at least partially, on the 604 memory unit and / or on the 602 processor (s). The term "computer-readable media" or "machine-readable media" should be considered as to include a single medium or multiple media (for example, a centralized or distributed database, and / or caches and associated servers) that store one or more sets of instructions. The term "computer-readable media" or "machine-readable media" should also be considered to include any media that is capable of storing, encoding or carrying a set of instructions for execution by the machine and that cause the machine to perform any one or more of the methodologies and / or processes of the present description. In addition, the term "computer-readable media" or "machine-readable media" in this way should be considered to include, but are not limited to, solid-state memories, and optical and magnetic media.
[0096] It should be understood that the processes and techniques described here are not inherently related to any particular device and can be implemented by any suitable combination of components. In addition, various types of general purpose devices can be used according to the precepts described here. It may also be advantageous to build a specialized apparatus to carry out the methods described herein. Those skilled in the art will realize that many different combinations of hardware, software, and firmware will be suitable for practicing the present description.
[0097] Therefore, the systems and methods described are well adapted to achieve the mentioned purposes and advantages, as well as those that are inherent here. The particular modalities described here are only illustrative, since the precepts of the present description can be modified and practiced in different but equivalent ways, apparent to those skilled in the art with the benefit of the precepts presented. In addition, it is not intended to make limitations on the details of construction or design shown here, other than those described in the following claims. It is therefore evident that the particular illustrative modalities described here can be altered, combined or modified and that all such variations are considered within the scope and spirit of the present description. The systems and methods illustratively described here can be properly practiced in the absence of any element that is not specifically described here and / or any optional element described here. Although compositions and methods are described in terms of "comprising", "containing" or "including" various components or steps, the compositions and methods can also "essentially consist" or "consist" of the various components and steps. All numbers and ranges described here may vary by a certain amount. Whenever a numerical range with a lower limit and an upper limit is described, any number and any range included in the range is specifically described. In particular, each range of values (of the form "from about aa to b" or, equivalently, "from approximately a to b" or, equivalently, "from approximately ab") is described here with the understanding of representing any number and range encompassed in the broadest range of values. Also, the terms in the claims have their normal ordinary meanings, unless otherwise explicitly and clearly defined by the claimant. In addition, the indefinite articles "one" or "one", as used in the claims, are defined here meaning one or more of one of the element it introduces. If there is any conflict in the uses of a word or term in this specification and one or more patents or other documents that may be incorporated herein by reference, definitions that are consistent with this specification must be adopted.

权利要求:
Claims (21)
[0001]
1. Method for optimizing weight measurements in drilling operations, characterized by the fact that it comprises: making (402) a first survey record at a first depth in a borehole, the first survey record providing the inclination and azimuth of a drilling column (106) at the first depth; measure (406) a weight on a drill bit (114) at the first depth with a sub sensor (208) arranged in a downhole assembly (104), the downhole assembly (104) forming part of the column drill (106) and the drill bit (114) being arranged at one end of the drill string (106); calculate (414) a borehole bend (118, 300) predicted at a second depth in the borehole (118, 300), the bend prediction bend (118, 300) being at least partially based on the slope and azimuth of the drilling column (106) at the first depth and a predicted slope and a predicted azimuth of the drilling column (106) at the second depth; drill (404) a gap from the first depth to the second depth along the predicted bore of the borehole (118, 300); measuring the weight on the drill bit (114) in real time as the drill column (106) moves along the gap; calculate (416) a weight correction value based on the predicted hole curvature; calibrate (418) the sub sensor (208) with the weight correction value; reprocessing the weight correction value based on the predicted borehole curvature (118, 300) as the drill column (106) moves along the gap; and real-time recalibrating the sub sensor (208) with a reprocessed weight correction value as the drill column (106) moves along the gap.
[0002]
2. Method according to claim 1, characterized by the fact that it additionally comprises: making a second survey register at the second depth, the second survey register providing the inclination and azimuth of the drill column (106) at the second depth; calculate a true borehole bore (118, 300) using the change in inclination and azimuth between the first and second depths; and reprocessing the weight correction value based on the actual curvature of the borehole (118, 300).
[0003]
3. Method according to claim 2, characterized by the fact that it additionally comprises: measuring the flexion of the downhole assembly (104) with the sub sensor (208); and detecting bending by bending the drill string (106) when the bending of the drill string (106) bends against the actual bend in the borehole (118, 300).
[0004]
4. Method according to claim 1, characterized by the fact that it additionally comprises: measuring the bending moment of the downhole assembly (104) with the sub sensor (208); and detecting buckling bending of the drill string (106) when the bending moment exceeds a predetermined limit.
[0005]
5. Method according to claim 1, characterized by the fact that it additionally comprises: measuring a torque on the drill bit (114) at the first depth with the sub sensor (208); calculate a torque correction value based on the predicted hole curvature; and calibrate the sub sensor (208) with the torque correction value.
[0006]
6. Method according to claim 5, characterized by the fact that it additionally comprises: drilling the interval from the first depth to the second depth based on the calculated torque correction value; measuring the torque on the drill bit (114) in real time as the drill column (106) moves along the gap; reprocessing the torque correction value based on the predicted hole curvature as the drill string (106) moves along the gap; and recalibrating the sub sensor (208) in real time with a reprocessed torque correction value as the drill string (106) moves along the gap.
[0007]
7. Method according to claim 6, characterized by the fact that it additionally comprises: making a second survey register at the second depth, the second survey register providing the inclination and azimuth of the drill column (106) at the second depth; calculate a true borehole bore (118, 300) using the change in inclination and azimuth between the first and second depths; and reprocessing the torque correction value based on the actual bore of the borehole (118, 300).
[0008]
8. Method according to claim 1, characterized by the fact that the weight correction value is determined using at least one of gravity and drag effects acting on the drill string (106).
[0009]
Method according to claim 8, characterized in that, as the predicted borehole curvature (118, 300) increases, the drag effects on the drilling column (106) increase.
[0010]
10. Non-transitory computer-readable media, characterized by the fact that it contains stored executable instructions per computer, which when executed by a computer processor perform the method as defined in claim 1.
[0011]
11. System to optimize weight measurements in drilling operations, characterized by the fact that it comprises: a well-bottom assembly (104) coupled to a drilling column (106) extended in a borehole (118, 300); one or more survey probes (207) arranged in the downhole assembly (104) and configured to make a first survey record at a first depth in the borehole (118, 300), the first survey record providing inclination and azimuth of the drill column (106) at the first depth; a sub sensor (208) arranged in the downhole assembly (104) and configured to measure a weight on the drill bit (114) at the first depth; a data acquisition system (504) coupled communicatively to one or more survey probes (207) and the sub sensor (208) and capable of receiving and processing the first survey record and the weight on the drill bit (114); and a corrective weight and torque model (508) coupled communicatively to the data acquisition system (504) and with one or more processors configured to calculate a borehole curvature (118, 300) predicted at a second depth in the borehole. borehole (118, 300), the predicted curvature of the borehole (118, 300) being at least partially based on the inclination and azimuth of the drilling column (106) at the first depth and an expected inclination and predicted azimuth of the drilling column (106) in the second depth, the one or more processors being additionally configured to calculate a weight correction value based on the predicted hole curvature, the weight correction value being used to calibrate the sub sensor (208).
[0012]
12. System according to claim 11, characterized by the fact that the corrective weight and torque model (508) is updated with weight measurements on the drill bit (114) in real time during drilling from an interval from the first depth to the second depth and additionally configured to reprocess the weight correction value as the drill column (106) moves along the gap, thereby recalibrating the sub sensor (208) with a reprocessed weight correction value.
[0013]
13. System according to claim 11, characterized by the fact that the weight correction value is determined using at least one of gravity and drag effects acting on the drill string (106).
[0014]
System according to claim 13, characterized in that, as the predicted borehole curvature (118, 300) increases, the drag effects on the drilling column (106) increase.
[0015]
15. System according to claim 11, characterized by the fact that the corrective weight and torque model (508) receives data from a steering model (510) configured to predict a change in the weight of the downhole set (104 ).
[0016]
16. System according to claim 11, characterized by the fact that the sub sensor (208) is configured to measure bending of the downhole assembly (104) to detect buckling bending of the drilling column (106).
[0017]
17. System according to claim 11, characterized by the fact that the sub sensor (208) is configured to measure the bending moment of the downhole assembly (104) to detect buckling bending of the drilling column (106) when the bending moment exceeds a predetermined limit.
[0018]
18. System according to claim 11, characterized by the fact that the sub sensor (208) is configured to measure a torque in the drill bit (114) at the first depth and the corrective weight and torque model (508) is configured to calculate a torque correction value based on the predicted hole curvature, the torque correction value being used to calibrate the sub sensor (208).
[0019]
19. System according to claim 18, characterized by the fact that the corrective weight and torque model (508) is configured to reprocess the weight and torque correction data once a second lifting record is made at the second depth and a true curvature of the borehole (118, 300) is calculated.
[0020]
20. System according to claim 11, characterized in that the data acquisition system (504) is arranged outside the borehole (118, 300).
[0021]
21. System according to claim 11, characterized by the fact that the data acquisition system (504) is arranged inside the borehole (118, 300).

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法律状态:
2018-12-04| B06F| Objections, documents and/or translations needed after an examination request according [chapter 6.6 patent gazette]|

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2019-12-17| B06U| Preliminary requirement: requests with searches performed by other patent offices: procedure suspended [chapter 6.21 patent gazette]|

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2021-01-19| B09A| Decision: intention to grant [chapter 9.1 patent gazette]|

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2021-03-30| B16A| Patent or certificate of addition of invention granted|Free format text: PRAZO DE VALIDADE: 20 (VINTE) ANOS CONTADOS A PARTIR DE 28/12/2012, OBSERVADAS AS CONDICOES LEGAIS. |

优先权:

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申请号 | 申请日 | 专利标题

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US201161580933P| true| 2011-12-28|2011-12-28|

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US61/580,933|2011-12-28|

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PCT/US2012/071917|WO2013101984A2|2011-12-28|2012-12-28|Systems and methods for automatic weight on bit sensor calibration and regulating buckling of a drillstring|

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