US20180149014A1

US20180149014A1 - Process to analyze mwd surveys from different bha runs in the same wellbore

Info

Publication number: US20180149014A1
Application number: US15/828,035
Authority: US
Inventors: Francis Chad Hanak
Original assignee: Individual
Current assignee: Super Holdings LLC
Priority date: 2016-11-30
Filing date: 2017-11-30
Publication date: 2018-05-31

Abstract

A process to analyze MWD surveys from different BHA runs in the same well bore in a combined fashion is presented herein. A processor is used to receive and analyze data provided through the generation of one or more BHA runs of a survey tool. The processor regulates the interaction of the various components within a control unit and facilitates calculation and analysis of the data produced to identify faults and their respective causes. For example, control unit may obtain Bayesian estimates and calculate an estimate of the mean survey error and a posteriori covariance corresponding to a full list of survey errors as multiple runs are completed. The process utilizes data from the entire wellbore to improve the observability of each error source. Consequently, fault detection, isolation, and recovery are much more robust.

Description

CLAIM OF PRIORITY

This application claims the benefit of U.S. Provisional Application No. 62/427,954, filed 30 Nov. 2016. The information contained therein is hereby incorporated by reference.

BACKGROUND

1. Field of the Invention

The present application relates to directional drilling, and in particular, to a process of analyzing multi-station analysis surveys from different runs in a combined fashion to improve fault detection, isolation, and recovery thereby resulting in a more accurate wellbore placement.

2. Description of Related Art

Traditional measurement while drilling (MWD) surveys are often quality checked and/or corrected for improved accuracy through a method called Multi-Station Analysis (MSA). MSA processes survey data one run at a time, which can make fault detection very difficult in the long straight sections of the wellbore where its use is of most value. Even when fault detection with MSA succeeds, isolating the cause of the fault is subject to a high level of ambiguity. For instance, errors in the magnetic reference field values can be difficult to distinguish from errors in the expected level if axial magnetic drill string interference. An inability to accurately isolate the cause of a fault can lead to an improper recovery from the fault, adding significant error to the estimated position of the wellbore.
Traditional MSA requires the user to determine if there is a fault in the data, and then to figure out the cause of the fault from a limited data set. Other survey analysis techniques look at surveys from individual Bottom Hole Assembly (BHA) runs in isolation, which leads to ambiguity in the results. Multiple faults can cause the same error signatures in the survey data, making this process fraught with error. If a fault is assumed where none exists, or the cause of an existing fault is incorrectly identified, the resulting survey corrections can add hundreds of feet of error to the well bore position.
Although strides have been made to provide to detect faults and isolate the respective causes, shortcomings remain. It is desired that a process be developed that utilizes data from the entire wellbore to improve the observability of each error source. Consequently, fault detection, isolation, and recovery are much more robust.

SUMMARY OF THE INVENTION

It is an object of the present application to provide a process for the precise estimation of the position of a wellbore during drilling. The process includes analyzing multi-station analysis surveys from different runs in a combined fashion to improve fault detection, isolation, and recovery thereby resulting in a more accurate wellbore placement.
It is a further object of the present application that the process more accurately detect faults and also isolate the cause of the faults. The new approach utilizes all of the BHA runs in the well to resolve ambiguity and improve wellbore placement accuracy. Vector measurements are obtained from a first survey tool at multiple survey stations in a borehole. Reference values describing the magnetic and gravitational field components are obtained along with specifications describing the a priori accuracy of the tool and the reference field parameters.
A list of survey errors and subsets of survey errors are defined from the list that partition the probability space of all combinations of listed survey errors. For each such subset, an estimate of the mean survey error and a posteriori covariance corresponding to the full list of survey errors is calculated using the survey tool measurements, expected reference field values, and only the a priori accuracy specifications corresponding to errors not included in said subset.
The process further includes the obtaining of a Bayesian estimate of the mean and a posteriori covariance of the full list of survey errors from the set of statistical estimates obtained previously, and a set of specified a priori probabilities for each partition of the aforementioned probability space. Vector measurements are obtained from one or more additional survey tools of the magnetic and gravitational fields at multiple survey stations in a borehole.
A Bayesian estimate of the mean and a posteriori covariance the survey errors corresponding to each of these additional survey runs into the borehole utilizing the above procedure. A combined statistical estimate of the survey errors corresponding to all survey tools run in the borehole is gathered by utilizing the Bayesian estimates from individual runs as correlated measurements. Alter a drilling parameter using the estimated deviations, the residual error covariance matrix, or both. Use of this process improve fault detection, isolation, and recovery thereby resulting in a more accurate wellbore placement. In this way, this assembly overcomes the disadvantages inherent in the prior art.
The more important features of the process have thus been outlined in order that the more detailed description that follows may be better understood and to ensure that the present contribution to the art is appreciated. Additional features of the process will be described hereinafter and will form the subject matter of the claims that follow.
Many objects of the present process will appear from the following description and appended claims, reference being made to the accompanying drawings forming a part of this specification wherein like reference characters designate corresponding parts in the several views.
Before explaining at least one embodiment of the process in detail, it is to be understood that the process is not limited in its application to the details of construction and the arrangements of the components and/or sequences of events set forth in the following description or illustrated in the drawings. The process is capable of other embodiments and of being practiced and carried out in various ways. Also it is to be understood that the phraseology and terminology employed herein are for the purpose of description and should not be regarded as limiting.
As such, those skilled in the art will appreciate that the conception, upon which this disclosure is based, may readily be utilized as a basis for the designing of other processes for carrying out the various purposes of the present process. It is important, therefore, that the claims be regarded as including such equivalent constructions insofar as they do not depart from the spirit and scope of the present process.

DESCRIPTION OF THE DRAWINGS

The novel features believed characteristic of the application are set forth in the appended claims. However, the application itself, as well as a preferred mode of use, and further objectives and advantages thereof, will best be understood by reference to the following detailed description when read in conjunction with the accompanying drawings, wherein:

FIG. 1 is an exemplary drilling system that includes a drilling rig engaged in drilling operations.

FIG. 2 is an exemplary schematic of a control unit.

FIG. 3 is a chart of data used within a control unit for processing according to the process of the present application.

FIG. 4 is a chart of steps performed through the control unit during analysis of data to determine faults and associated causes of error.

While the assembly and method of the present application is susceptible to various modifications and alternative forms, specific embodiments thereof have been shown by way of example in the drawings and are herein described in detail. It should be understood, however, that the description herein of specific embodiments is not intended to limit the application to the particular embodiment disclosed, but on the contrary, the intention is to cover all modifications, equivalents, and alternatives falling within the spirit and scope of the process of the present application as defined by the appended claims.

DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENT

Illustrative embodiments of the preferred embodiment are described below. In the interest of clarity, not all features of an actual implementation are described in this specification. It will of course be appreciated that in the development of any such actual embodiment, numerous implementation-specific decisions must be made to achieve the developer's specific goals, such as compliance with system-related and business-related constraints, which will vary from one implementation to another. Moreover, it will be appreciated that such a development effort might be complex and time-consuming but would nevertheless be a routine undertaking for those of ordinary skill in the art having the benefit of this disclosure.
In the specification, reference may be made to the spatial relationships between various components and to the spatial orientation of various aspects of components as the devices are depicted in the attached drawings. However, as will be recognized by those skilled in the art after a complete reading of the present application, the devices, members, apparatuses, etc. described herein may be positioned in any desired orientation. Thus, the use of terms to describe a spatial relationship between various components or to describe the spatial orientation of aspects of such components should be understood to describe a relative relationship between the components or a spatial orientation of aspects of such components, respectively, as the assembly described herein may be oriented in any desired direction.
The process and method in accordance with the present application overcomes one or more of the above-discussed problems commonly associated with elevated platforms discussed previously. In particular, the process provides for the precise estimation of the position of a wellbore during drilling. The process includes analyzing multi-station analysis surveys from different runs in a combined fashion to improve fault detection, isolation, and recovery thereby resulting in a more accurate wellbore placement. These and other unique features of the assembly are discussed below and illustrated in the accompanying drawings.
The process and method will be understood, both as to its operation, from the accompanying drawings, taken in conjunction with the accompanying description. Several embodiments of the process may be presented herein. It should be understood that various components, parts, and features of the different embodiments may be combined together and/or interchanged with one another, all of which are within the scope of the present application, even though not all variations and particular embodiments are shown in the drawings. It should also be understood that the mixing and matching of features, elements, and/or functions between various embodiments is expressly contemplated herein so that one of ordinary skill in the art would appreciate from this disclosure that the features, elements, and/or functions of one embodiment may be incorporated into another embodiment as appropriate, unless otherwise described.
Referring now to the Figures wherein like reference characters identify corresponding or similar elements in form and function throughout the several views. The following Figures assist in describing the process of the present application and its associated features. It should be noted that the articles “a”, “an”, and “the”, as used in this specification, include plural referents unless the content clearly dictates otherwise.
Referring now to FIG. 1 in the drawings, an exemplary drilling system 101 is illustrated. System 101 includes a drilling rig engaged in drilling operations. The exemplary drilling rig includes a derrick 1, draw works 2, cable 3, crown block 4, traveling block 5, and hook 6 supporting a drill string 50 disposed in a borehole penetrating formation 52. The drill string 50 includes a swivel joint 7, kelly 8, drill pipe 9, drill collars 10, and drill bit 11. Pumps 12 circulate drilling fluid through a standpipe 13 and flexible hose 14, down through the hollow drill string 50 and back to the surface through the annular space 15 between the drill string 50 and the borehole wall 16. A steering device 40 is disposed on the downhole portion of the drill string 50 in order to provide a physical mechanism by which an orientation or direction of the drill bit 11 may be altered to deviate from its current drilling direction towards another drilling direction. This steering device 40 may therefore be used to produce deviated sections or curved sections of the borehole 48.
During the course of drilling the borehole 48, it is advantageous to measure from time to time the orientation and location of the borehole 48 in order to determine its trajectory. This may be accomplished by the use of a survey tool 17 located within the drill collars 10 of the drill string 50. The survey tool 17 obtains survey measurements such as the direction and magnitude of the local gravitational and magnetic fields with respect to a tool-fixed coordinate system. The survey measurements may be used to determine inclination and azimuth of the borehole 48. It is customary to take a survey each time the drilling operation is interrupted to add a new section to the drill string 50, which is typically about 30 meters or 100 feet. However, survey measurements may be taken at any time.
The survey measurements may be transmitted to the surface by a suitable telemetry system, such as such as electromagnetic telemetry methods or acoustic signal telemetry, or by using a modulating valve (not shown) placed in the flow passage within or adjacent to survey tool 17 that causes pressure pulses to propagate in the mud column up the drill string. Such pressure pulses may be detected by a pressure transducer 18 placed in the standpipe 13 and communicated to control unit 24 which may be located on the rig floor or in a logging trailer or other work area. Alternately, the control unit 24 may be disposed at a downhole location along the drill string, and the survey measurements may be transmitted to the downhole control unit.
The exemplary control unit 24 may include a processor 26, a memory location 28 containing data related to survey measurements, such as magnetometer measurements, magnetometer biases, accelerometer measurements, accelerometer biases, and other errors, and a set of programs 30. The processor 26 may access the programs 30 to perform the exemplary methods disclosed herein for altering a drilling parameter using, in part, the measurements stored in memory location 30. The measurements stored in the memory 30 may include data obtained at a plurality of boreholes proximate the current borehole 48. The survey measurements may further include data related to errors or uncertainties in the obtained survey measurements as well as errors related to survey parameter obtained in nearby boreholes. Such errors may include errors due to magnetometer biases, gravimeter biases, errors in magnetic field measurements and dip measurements.
FIG. 2 illustrates a more detailed view of exemplary control unit 24. The control unit 24 includes an input/output (I/O) interface 53, a processor 26, a database 54, and a maintenance interface 56. Alternative embodiments can combine or distribute the input/output (I/O) interface 53, processor 26, database 54, and maintenance interface 56 as desired. Embodiments of the control unit 24 can include one or more computers that include one or more processors and memories configured for performing tasks described herein. This can include, for example, a computer having a central processing unit (CPU) and non-volatile memory that stores software instructions for instructing the CPU to perform at least some of the tasks described herein. This can also include, for example, two or more computers that are in communication via a computer network, where one or more of the computers includes a CPU and non-volatile memory, and one or more of the computer's non-volatile memory stores software instructions for instructing any of the CPU(s) to perform any of the tasks described herein. Thus, while the exemplary embodiment is described in terms of a discrete machine, it should be appreciated that this description is non-limiting, and that the present description applies equally to numerous other arrangements involving one or more machines performing tasks distributed in any way among the one or more machines. It should also be appreciated that such machines need not be dedicated to performing tasks described herein, but instead can be multi-purpose machines, for example computer workstations, that are suitable for also performing other tasks. Furthermore the computers may use transitory and non-transitory forms of computer-readable media. Non-transitory computer-readable media is to be interpreted to comprise all computer-readable media, with the sole exception of being a transitory, propagating signal.
The I/O interface 53 provides a communication link between external users, systems, and data sources and components of the control unit 24. The I/O interface 53 can be configured for allowing one or more users to input information to the control unit 24 via any known input device. Examples can include a keyboard, mouse, touch screen, microphone, and/or any other desired input device. The I/O interface 53 can be configured for allowing one or more users to receive information output from the control unit 24 via any known output device. Examples can include a display monitor, a printer, a speaker, and/or any other desired output device. The I/O interface 53 can be configured for allowing other systems to communicate with the control unit 24. For example, the I/O interface 53 can allow one or more remote computer(s) to access information, input information, and/or remotely instruct the control unit 24 to perform one or more of the tasks described herein. The I/O interface 53 can be configured for allowing communication with one or more remote data sources. For example, the I/O interface 53 can allow one or more remote data source(s) to access information, input information, and/or remotely instruct the control unit 24 to perform one or more of the tasks described herein.
The database 54 provides persistent data storage for control unit 24. While the term “database” is primarily used, a memory or other suitable data storage arrangement may provide the functionality of the database 54. In alternative embodiments, the database 54 can be integral to or separate from the control unit 24 and can operate on one or more computers. The database 54 preferably provides non-volatile data storage for any information suitable to support the operation of the control unit 24, including various types of data discussed herein. Database 54 may be combined with or operably communicated to memory location 28 for the storage and use of vector measurements, reference values describing the magnetic and gravitations field components from a variety of reference field models or in-field data sources, specifications of the priori accuracy of the tools and reference field parameters, survey errors, and so forth.
The maintenance interface 56 is configured to allow users to maintain desired operation of the control unit 24. In some embodiments, the maintenance interface 56 can be configured to allow for reviewing and/or revising the data stored in the database 54 and/or performing any suitable administrative tasks commonly associated with database management. This can include, for example, updating database management software, revising security settings, and/or performing data backup operations. In some embodiments, the maintenance interface 56 can be configured to allow for maintenance of the processor 26 and/or the I/O interface 53. This can include, for example, software updates and/or administrative tasks such as security management and/or adjustment of certain tolerance settings.
The processor 26 is configured for regulating the interaction of the various components within control unit 24 and for facilitating calculation and analysis of the data produced to identify faults and their respective causes. For example, control unit 24 may obtain Bayesian estimates and calculate an estimate of the mean survey error and a posteriori covariance corresponding to a full list of survey errors as multiple runs are completed. The processor 26 is configured to regulate and handle the operation of control unit 24. The processor 26 can include various combinations of one or more processors, memories, and software components.
The borehole inclination may be determined by use of the gravitational measurements alone, while the borehole azimuth may be determined from the gravitational and magnetic measurements. Since the azimuth uses the direction of the local magnetic field as a north reference, the survey tool 17 may be placed in non-magnetic portions 19 and 20 of the drill string situated between upper and lower ferromagnetic sections 21 and 22. Magnetization of the upper and lower ferromagnetic sections 21 and 22, as well as imperfections in the non-magnetic materials comprising the survey tool 17 and the non-magnetic collars 19 and 20 may produce a magnetic error field, which is fixed in the tool's frame of reference and which therefore appears as bias errors affecting the magnetic measurements.
The process and method of the present application is illustrated in the charts of FIGS. 3 and 4. In FIG. 3, data used within control unit 24 and received and analyzed via processor 26 is shown. The process includes the calculation and analysis of data through a particular software program via processor 26 of control unit 24. Processor 26 may process different data types generated over time from different runs to identify the faults and respective causes through various estimations, specifications, and collected data. Exemplary data required and produced through the process of the present application is the following: magnetic directional survey data 70 from one or multiple surveying runs into a wellbore, specifications 72 describing the a priori accuracy of the sensors used in each surveying run, magnetic and gravitational reference field component values 74, specifications 76 describing the accuracy of the reference field component values, Bayesian estimate 78 of the sensor error and reference field parameters given the measurements from a single surveying run based on a partition of the probability space in terms of possible survey faults, a combined statistical estimate 80 of the sensor error and reference field parameters from all BHA runs in the wellbore using the per-run Bayesian estimates as measurements, and survey corrections 82 generated from the combined statistical estimate. Additional features and functions of the device are illustrated and discussed below.
In FIG. 4, a series of steps are outlined in a chart for execution by the software program run via control unit 24. The software is hosted in a computational device (i.e. control unit 24 or any electronic device in communication therewith) containing a processor 26, and able to receive the survey measurements 70 and the reference field component values 76. The survey measurements 70, reference field component values 76, and the a priori information 72/76 for each survey run are used to create a Bayesian estimate for the survey errors and reference field component offsets for each survey run in the wellbore 78. The Bayesian per-run estimates are fed together to an estimation algorithm that statistically combines them to get an improved, combined estimate of the reference field component offsets and the sensor errors for each survey run 80. These sensor error estimates are used to correct the original survey measurements, resulting in a corrected survey of the wellbore 82.
For each survey run in the wellbore, the probability space encompassing all combinations of measurement and reference field faults is partitioned. For each element in the partition, the appropriate components of the a priori data 72/76 are used to estimate the sensor and reference field component errors for that run. The difference between the reference field components 74 and the survey measurements 70 are used as the measurements in the estimation process. The estimated solution for each part of the partitioned probability space is combined in a Bayesian fashion to generate the Bayesian estimate for the survey run 78. This is done for each survey run in the wellbore, or possibly an entire pad. Then the Bayesian per-run estimates are statistically combined, properly accounting for correlations, to get an improved, combined estimate of the reference field component offsets and the sensor errors for each survey run 82. These sensor error estimates are used to correct the original survey measurements, leading to a corrected survey of the well bore that is unambiguous and more accurate than is typically available.
All of the elements are necessary to form a working version of the invention. Inclusion of survey data from additional nearby wells that see substantially the same magnetic and gravitational reference field components would improve the accuracy of the result, although they are not necessary.
In practice, a user would provide the compiled software program having survey measurements from at least one run in a wellbore. Ideally multiple runs in the same wellbore are preferred. The user also provides the program with the required magnetic and gravitational reference field component values, and the a priori accuracy specifications. The statistical algorithms within the software program would then process the data, correct the surveys, and provide the corrected surveys to the user in a designated format.
The particular steps disclosed above are illustrative only, as the application may be modified and practiced in different but equivalent manners apparent to those skilled in the art having the benefit of the teachings herein. It is therefore evident that the particular steps disclosed above may be altered or modified, and all such variations are considered within the scope and spirit of the application. Accordingly, the protection sought herein is as set forth in the description. It is apparent that an application with significant advantages has been described and illustrated. Although the present application is shown in a limited number of forms, it is not limited to just these forms, but is amenable to various changes and modifications without departing from the spirit thereof.

Claims

What is claimed is:

1. A method of drilling a borehole including a processor and communications system, comprising:

obtaining vector measurements from a first survey tool of magnetic and gravitational fields at multiple survey stations in a borehole;

obtaining reference values describing magnetic and gravitational field components from at least any of a variety of reference field models source or an in-field data source;

obtaining specifications describing a priori accuracy of the first survey tool and reference field parameters;

defining a list of survey errors;

defining subsets of survey errors from a list that partitions a probability space of all combinations of listed survey errors;

calculating an estimate of a mean survey error and a posteriori covariance corresponding to the list of survey errors for each subset using the processor, the estimate being calculated using the survey tool measurements, expected reference field values, and only the a priori accuracy specifications corresponding to errors not included in the subsets;

obtaining a Bayesian estimate of the mean survey error and the a posteriori covariance of the list of survey errors from the set of statistical estimates obtained in the previous step, and a set of specified a priori probabilities for each partition of the probability space;

obtaining vector measurements from one or more additional survey tools of the magnetic and gravitational fields at multiple survey stations in a borehole;

obtaining a Bayesian estimate of the mean and a posteriori covariance the survey errors corresponding to each of these additional runs of survey tools into the borehole;

obtaining a combined statistical estimate of the survey errors corresponding to all survey tools run in a borehole by utilizing the Bayesian estimates from individual runs as correlated measurements; and

altering a drilling parameter using at least one of estimated deviations and a residual error covariance matrix.

2. The method of claim 1, wherein the Bayesian estimates that are combined include survey runs from multiple boreholes originating from at least one of the same well pad and the same field.

3. The method of claim 1, further comprising:

partitioning the probability space encompassing all combinations of measurement and reference field faults for each survey run in the wellbore.

4. The method of claim 1, further comprising:

performing multiple runs of the first survey tool.

5. The method of claim 1, further comprising:

statistically combining the Bayesian run estimates for each run of the survey tool to form a combined estimate of the reference field component offsets and the sensor errors for each survey run.