HK1209471B - Inground operations, system, communications and associated apparatus, and method - Google Patents

Description

Underground operations, systems, communications, and related devices and methods

Related applications

This application claims priority to U.S. Provisional Patent Application No. 61/674,248, filed July 20, 2012, the entire contents of which are incorporated herein by reference. This application also claims priority to U.S. Non-Provisional Patent Application Nos. 13/946,284 and 13/946,611, filed July 19, 2013, the entire contents of which are incorporated herein by reference.

Technical Field

The present application relates generally to inground operations and, more particularly, to advanced systems, apparatus, and methods for conducting such inground operations in a manner heretofore unknown.

Background Art

A technique commonly referred to as horizontal directional drilling (HDD) can be used to install utilities without the need to dig a trench. A typical utility installation involves the use of a drill rig with a drill string that supports a drill tool at its distal or buried end. The drill rig forces the drill tool through the ground by applying thrust to the drill string. The drill tool is guided during extension of the drill string to form a pilot hole. After the pilot hole is completed, the distal end of the drill string is attached to a pullback device, which is in turn attached to the front end of the utility. The pullback device and utility are then pulled through the pilot hole using the retraction of the drill string to complete the installation. In some cases, the pullback device may include a reaming tool that is used to expand the diameter of the pilot hole in front of the utility so that the installed utility can have a larger diameter than the initial diameter of the pilot hole.

Compared to the existing practice of digging trenches along the entire installation path, such trenchless utility installations are generally well-suited for developed areas. HDD has also proven practical for installing utilities in locations where trenching is not feasible, such as beneath rivers, buildings, or some other obstruction, man-made structure, or other object. Unfortunately, there are some risks associated with trenchless utility installations. For example, there may be pre-existing utilities that intersect the intended path for the installation of the new utility. In some cases, the location of the pre-existing utilities is known, however, this is not always the case. Therefore, there is a risk associated with inadvertently drilling into unknown pre-existing utilities. The prior art includes several methods that attempt to address this problem, which are described immediately below.

U.S. Patent No. 5,457,995 (hereinafter the '995 patent) issued to Staton teaches one approach. Staton attempts to use acoustic information in combination with seismic information to detect whether a drill tool has encountered a pre-existing utility. Unfortunately, the technique requires background knowledge of the pre-existing utility and physical contact with the pre-existing utility. For at least these reasons, the technique is not suitable for detecting encounters with unknown pre-existing utilities. It should be noted that the patent briefly describes monitoring the thrust applied to the drill string and used in combination with acoustic and seismic information. Specifically, the '995 patent describes monitoring the hydraulic thrust at the drill rig based on an increase in thrust as an indication of a believed impact with a utility. However, the '995 patent also acknowledges that the thrust may not increase, depending on the material forming the utility, and in this case, does not appear to provide any solution. The applicant further recognizes that, as will be described in detail below, the thrust at the drill rig does not necessarily represent the force applied by the drill tool to the soil.

Another approach taken by the prior art is described in U.S. Patent No. 6,614,354 (hereinafter referred to as the '354 patent). This patent teaches a technique for detecting contact with a buried pipeline based on monitoring acoustic sensors and impressed current sensors. Unfortunately, as with the '995 patent, this technique requires background knowledge of the presence of the pipeline and physical contact with it.

During HDD operations, whether for drilling a pilot hole or installing utilities during pullback or back-reaming, drilling fluid or mud is typically conveyed through the drill string to be discharged from the buried end. During drilling, the mud can be discharged from the drill bit at this high pressure, which helps to cut into the soil and/or rock at the end face of the pilot hole. The mud can then flow back to the drill rig in the opposite direction in an annular area surrounding the drill tool and drill string while transporting the drill cuttings back to the surface. The drilling mud can also be used to cool the drill bit and provide lubrication. During pullback/back-reaming operations, when the drill string is retracted, the drilling mud can be discharged from the leading face of the back-reaming tool at high pressure to assist in cutting into the soil and provide lubrication to the utilities being installed in order to reduce tension on the utilities. As in drilling operations, drilling fluid can also be used to transport drill cuttings in an uphole direction.

With the foregoing in mind, another risk associated with trenchless utility installation involves what is commonly referred to as "frac-out." Instead of following the path uphole defined by the pilot hole after exiting the inground tool, pressurized mud can sometimes escape through fractures in the ground. The escaped mud can damage roads or other structures and can pose environmental concerns. As will be described in detail below, applicants have also recognized unprecedented methods and apparatus for frac-out detection. Further benefits are described below with respect to the described techniques for frac-out and cross-hole detection. For example, certain operating conditions associated with the discharge of drilling mud from the drill bit ejector can be detected.

Another risk associated with trenchless utility installation involves what may be referred to as key-holing. This latter term describes the tendency of a utility to straighten a curve during a pullback operation. Applicants have recognized that the result of key-holing can be an undesirable intersection of a new utility with a pre-existing utility or other buried obstructions. Applicants have further recognized and describe below a previously unseen method and apparatus for detecting key-holing.

The present disclosure discloses several other improvements, such as those related to system communications, determination of the depth of an inground tool, and advanced guidance techniques suitable for inground conditions that typically present difficulties in guiding a drill tool.

The foregoing examples of the prior art and their related limitations are intended to be illustrative, not exclusive, and other limitations of the prior art will become apparent to those skilled in the art upon reading this specification and studying the accompanying drawings.

Summary of the Invention

The following embodiments and aspects thereof are described and illustrated in conjunction with systems, tools, and methods that are intended to be exemplary and illustrative, not limiting in scope.In various embodiments, one or more of the above-mentioned issues have been considered, while other embodiments are directed to other matters.

In one aspect of the present invention, a method and associated apparatus for use in conjunction with a horizontal directional drilling system are described. The horizontal directional drilling system includes a drill string extending from a drill rig to an inground tool, such that extension and retraction of the drill string during inground operations generally produces corresponding movement of the inground tool. The drill string defines a passageway for carrying pressurized flow of drilling mud from the drill rig to the inground tool to discharge the drilling mud from the inground tool. During the inground operation, mud annulus pressure in the ground surrounding the inground tool is monitored. A change in the mud annulus pressure is detected. Based at least in part on the change, a response is initiated as an indication of one of a potential cross-hole and a potential fracture leak.

In another aspect of the present invention, a method and associated apparatus for use in conjunction with a horizontal directional drilling system are described. The horizontal directional drilling system includes a drill string extending from a drilling rig to an inground tool, such that extension and retraction of the drill string during inground operations moves the inground tool through the subsurface. The drill string defines a passageway for carrying pressurized drilling mud from the drilling rig to the inground tool for discharge from the inground tool. During the drilling operation, mud annulus pressure in a pilot hole surrounding the inground tool is monitored. An increase in the mud annulus pressure exceeding an upper downhole pressure limit is detected. A response is initiated based at least in part on the detection of the increase.

In another aspect of the present invention, a method and associated apparatus are described for use in conjunction with a horizontal directional drilling system including a drill string extending from a drill rig to an inground tool having a drill bit, such that during a drilling operation, extension of the drill string advances the drill tool through the subsurface to form a pilot hole. During advancement of the drill tool, a drill bit force exerted by the drill bit on the pilot hole face is monitored. A drop in the drill bit force is detected, and a response is initiated based at least in part on the detected drop as an indication of a potential cross-hole.

In another aspect of the present invention, a method and associated apparatus are described for use in conjunction with a system for conducting in-ground operations, the system utilizing at least a drill string extending from a drilling rig to an in-ground tool and a walkover detector as at least one of a homing beacon and a tracking device. A downhole transceiver is located downhole near the in-ground tool. The portable transceiver forms part of the walkover locator. A first two-way communication link is constructed between the uphole transceiver and the downhole transceiver, the first two-way communication link using the drill string as an electrical conductor to provide communication between the uphole transceiver and the downhole transceiver, and a second two-way communication link is constructed between the portable transceiver of the walkover detector and the downhole transceiver, the second two-way communication link utilizing wireless electromagnetic communication between the portable transceiver of the walkover detector and the downhole transceiver so that information generated by the walkover detector can be transmitted to the uphole transceiver by transmitting information from the walkover detector to the downhole transceiver via the second two-way communication link, and thereafter by transmitting information from the downhole transceiver to the uphole transceiver via the first two-way communication link.

In another aspect of the present invention, a method and associated apparatus for use in conjunction with a horizontal directional drilling system are described. The horizontal directional drilling system includes a drill string extending from a drilling rig to an inground tool, such that extension of the drill string during inground operations generally produces corresponding movement of the inground tool through the subsurface. The drill string defines a passageway for carrying pressurized drilling mud from the drilling rig to the drill tool, thereby discharging the drilling mud from the drill tool. Uphole mud pressure is detected to be at or above an uphole mud pressure threshold. In response to detecting that the uphole mud pressure is at or above the uphole mud pressure threshold, a current value of downhole mud annular pressure in an annular region surrounding the drill tool is determined. The current value of the downhole mud annular pressure is compared to the downhole mud pressure threshold. In response to the current value of the downhole mud annular pressure being at or below the downhole mud pressure threshold, a current mud flow rate through the drill string is determined. The current mud flow rate is compared to the mud flow rate threshold. In response to the current mud flow rate being at or below the mud flow rate threshold, a response is initiated.

In another aspect of the present invention, a method and associated apparatus for use in conjunction with a horizontal directional drilling system is described. The horizontal directional drilling system includes a drill string for performing inground operations, the drill string having a length extending from a drill rig to an inground tool, the drill string moving the inground tool along a path through the ground, the motion of the drill string being characterized at least in part by the pitch orientation of the inground tool. The motion of the drill string is measured to characterize the motion as a series of incremental motions of the inground tool based on the length of the drill string. The pitch orientation of the inground tool is established in association with each incremental motion. An incremental depth change along the depth of the inground tool is determined for each incremental motion, such that each incremental motion serves as a pitch measurement interval. The incremental depth changes are summed as part of determining a current depth of the inground tool at a current location.

In another aspect of the present invention, a method and associated apparatus are described for use in conjunction with a horizontal directional drilling system during inground operations. The inground operations include a pullback operation in which a drill string is pulled back by a drill rig to pull a utility at least approximately along a pilot hole, thereby potentially creating a keyhole situation in which the utility is inadvertently displaced above the initial path of the pilot hole. A pilot hole is formed by advancing the drill tool through the ground in response to extension of the drill string from the drill rig while measuring the length of the drill string extending from the drill rig to the drill tool. As the drill tool advances, at least one parameter characterizing the pilot hole is recorded at a series of locations along the pilot hole, the at least one parameter being represented by the measured length of the pilot hole for each location in the series. After the pilot hole is formed, a pullback tool is attached to the distal end of the drill string, and the utility is attached to the pullback tool. During the pullback operation, the drill string is retracted to pull the pullback tool and utility at least approximately along the pilot hole toward the drill rig while measuring the length of the drill string extending from the drill rig to the pullback tool. During the pullback, at least a current value of a parameter represented by a measured length of the drill string is characterized. The current value of the parameter, obtained at a current position of the pullback tool during the pullback operation, is compared with a recorded value of the parameter obtained during the formation of the pilot hole and corresponding to the current position. A response to at least the potential occurrence of drill string keying is initiated based on a deviation of the current value of the parameter from the recorded value.

In another aspect of the present invention, a method and associated apparatus for use in conjunction with a horizontal directional drilling system are described. The horizontal directional drilling system includes a drill string having a length extending from a drill rig to a drill tool having a drill bit, such that extension of the drill string during a drilling operation advances the drill tool through the ground to form a pilot hole. A carving interval is performed by advancing the drill string to engage the drill bit with an end face of the pilot hole while rotating the drill bit from a starting angular position to an ending angular position less than one full rotation. The drill string is retracted in coordination with sensing a drill bit force acting on the end face. The drill string is rotated in coordination with terminating retraction based on the sensed drill bit force to return the drill bit to the starting angular position such that the drill bit force acting on the end face is at least partially relieved. One or more automatic carving iterations are performed by repeating advancement, drill string retraction, and drill string rotation.

In another aspect of the present invention, a method and associated apparatus are described for use in conjunction with a horizontal directional drilling system including a drill string extending from a drilling rig to an inground tool, such that extension and retraction of the drill string during inground operations generally produces corresponding movement of the inground tool. A downhole parameter representative of the inground tool is sensed. An uphole parameter representative of at least one operating condition is sensed at the drilling rig. A response to detection of at least one adverse operating condition is automatically initiated based on the downhole parameter and at least in part on the uphole parameter.

In another aspect of the present invention, a method and associated apparatus are described for use in conjunction with a system for conducting inground operations, the system utilizing at least a drill string extending from a drilling rig to an inground tool and at least a portable locator for receiving a locating signal transmitted from the inground tool. An uphole transceiver is located near the drilling rig. The portable transceiver forms a portion of the portable locator and is configured to receive the locating signal to at least periodically update a depth reading of the inground tool. A telemetry link is configured for at least bidirectional communication via the portable locator telemetry signal from the portable transceiver of the portable locator to the uphole transceiver to periodically transmit at least the depth reading to the uphole transceiver. A processor is configured to monitor the telemetry link to detect signal attenuation of the portable locator telemetry signal and, in response to detecting such signal attenuation, switch the periodic transmission of the depth reading to a different communication path for receipt by the uphole transceiver.

BRIEF DESCRIPTION OF THE DRAWINGS

Exemplary embodiments are illustrated in the referenced drawings.The embodiments and drawings disclosed herein are intended to be illustrative rather than restrictive.

1 is a schematic elevational view of a system utilizing a signal coupler through a drill string in the context of cross-hole detection and other features of the present invention.

FIG. 2 is a schematic perspective view of one embodiment of a coupling adapter of the present invention.

FIG. 3 is a schematic exploded perspective view of the embodiment of the coupling adapter of FIG. 2 , and is shown here to illustrate details of the structure of the coupling adapter.

4 is a schematic exploded elevational and partially cutaway view of the embodiment of the coupling adapter of FIGS. 2 and 3 , shown here to further illustrate details of the structure of the coupling adapter.

5 is a schematic elevational and partially cut-away assembly view of the embodiment of the coupling adapter of FIGS. 2-4 , illustrating details regarding the assembled configuration of the coupling adapter.

6 is a further enlarged elevational and partially cutaway view of the portion taken within circle 6 - 6 of FIG. 5 , shown here to illustrate details of the electrical connections in the embodiment of FIG. 5 with respect to the coupling adapter.

7a is a schematic, partially cut-away elevational view illustrating another embodiment of a coupling adapter of the present invention that electrically isolates two conductors of a current transformer from a drill string.

7b is a schematic front and partially cut-away exploded view of the embodiment of the coupling adapter of FIG. 7a , shown here to further illustrate details of the structure of the coupling adapter.

7c is a further enlarged schematic elevational and partially cutaway view of the portion taken within circle 7c-7c of FIG. 7a, shown here to illustrate details of the electrical connections in the embodiment of FIGs. 7a and 7b.

8 is a schematic perspective view of one embodiment of an inground tool in the form of a drill bit and an inground housing connected to the coupling adapter of the present invention.

9 is a schematic perspective view of another embodiment of an inground tool and reaming tool in the form of a tension monitor connected to a coupling adapter of the present invention.

FIG. 10 is a block diagram illustrating one embodiment of an electronic portion that may be used with the coupling adapter of the present invention.

11 is a block diagram illustrating one embodiment of the electronics that may be used at a drill rig or as part of a drill string repeater in conjunction with the coupling adapter of the present invention acting as an inground tool.

12a is a flow chart illustrating an embodiment of a method for monitoring various combinations of data from rig-based sensors and downhole-based sensors to provide detection of various detrimental operating conditions.

12b is a flow chart illustrating an embodiment of a method for monitoring various combinations of data from rig-based sensors and downhole-based sensors to provide detection of cross-bore encounters.

FIG. 13 is a block diagram illustrating an embodiment of a data structure for use with methods and apparatus according to the present invention.

14a-14c are screen shots illustrating embodiments of how operator notifications may appear based on the methods described herein.

FIG. 15 a includes a plurality of operating parameters plotted with respect to time for the purpose of illustrating various operating conditions in accordance with the present invention.

FIG. 15 b is an enlarged graph based on a portion of the graph of FIG. 15 a and further illustrates the drill rig thrust and the drill bit force in time relationship.

16 is a further enlarged schematic diagram of the inground tool and the distal end of the drill string of FIG. 1 , which is shown here to describe details of the integrated depth technique according to the present invention.

17 is a flow chart illustrating an embodiment of a method for performing an integrated depth technique.

FIG. 18 is a schematic elevational view of an area undergoing a backreaming operation, and is shown here to illustrate the occurrence of drill string keying and to characterize the drill string keying from an analytical perspective.

FIG. 19 is a flow chart illustrating an embodiment of a method for detecting a keyhole in the drill string shown in FIG. 18 .

FIG. 20 is a schematic diagram representing the roll orientation of a drill bit.

FIG. 21 is a flow chart showing an embodiment of an automatic notching method according to the present invention.

22 is a flow chart illustrating an embodiment of a method for monitoring a telemetry link between a portable device and a drilling rig.

23 is a flow chart illustrating another embodiment of a method for monitoring a telemetry link between a portable device and a drilling rig.

DETAILED DESCRIPTION

The following description is provided to enable one of ordinary skill in the art to make and use the invention, and is provided in the context of patent applications and their requirements. Various modifications to the described embodiments will be apparent to those skilled in the art, and the general principles taught herein may be applied to other embodiments. Therefore, the present invention is not intended to be limited to the embodiments shown, but is to be accorded the widest scope, including modifications and equivalents, consistent with the principles and features described herein, as defined by the scope of the appended claims. It should be noted that the accompanying drawings may not be drawn to scale and are illustrated in nature in a manner that is considered to best illustrate the features of interest. Descriptive terminology may be used with respect to these descriptions, however, such terminology is employed to facilitate the reader's understanding and is not intended to be limiting. In addition, the drawings are not drawn to scale for purposes of clarity.

Turning now to the drawings, wherein like parts are designated by like reference numerals throughout the various figures, attention is directed immediately to FIG1 , which is a front elevational view schematically illustrating an embodiment of a horizontal directional drilling system, generally designated 10, and constructed in accordance with the present invention. While the illustrated system illustrates the present invention within the context of a horizontal directional drilling system and components thereof for performing in-ground drilling operations, the present invention enjoys equal applicability with respect to other operating procedures, including, but not limited to, vertical drilling operations, pullback operations for installing utilities, survey operations, and the like.

FIG1 illustrates a system 10 operating in an area 12. The system 10 includes a drilling rig 14 having a drill string 16 extending from the drilling rig 14 to a drilling tool 20. The drill string can be pushed into the ground to move an inground tool 20 at least generally in an advancing direction 22 as indicated by the arrow. While the present example is constructed with respect to the use of a drilling tool, it will be appreciated that the discussion is applicable to any suitable form of inground tool, including but not limited to reaming tools, tension monitoring tools used during pullback operations where utilities or casings may be installed, and survey tools for surveying the borehole path, such as using an inertial guidance unit and downhole pressure monitoring. In the operation of the drilling tool, monitoring is typically required based on the advancement of the drill string, while in other operations, such as pullback operations, monitoring is typically performed in response to the retraction of the drill string.

Continuing with reference to FIG1 , a drill string 16 is partially shown and segmented. The drill string 16 is composed of a plurality of detachably connected individual drill pipe segments, some of which are designated 1, 2, n-1, and n. The drill pipe segments have segment lengths or section lengths and wall thicknesses. The drill pipe segments can be interchangeably referred to as drill rods, which have rod lengths. During operation of the drilling rig, drill pipe segments can be added to the drill string one at a time and pushed into the ground by the drilling rig using a movable reciprocating table 23 to advance the inground tool. The drilling rig 14 may include a suitable monitoring device 24 (which may form part of a control console, yet to be described) for measuring the movement of the drill string into the ground, as described, for example, in U.S. Patent No. 6,035,951 (hereinafter the '951 patent), entitled "SYSTEMS, ARRANGEMENTS AND ASSOCIATED METHODS FOR TRACKING AND/OR GUIDING AN UNDERGROUND BORING TOOL," which is assigned to the same applicant as the present application and is incorporated herein by reference. It will be appreciated that the drilling rig monitoring device may monitor essentially any aspect of the operation of the drilling rig. In this embodiment, the clamp monitor 26 may monitor the status of the clamp used to grip the uphole end of the drill string when a new drill pipe section is installed on the drill string. This operation involves applying a high torque to the new drill pipe section as it threadably engages the uphole end of the drill string. The drill rig monitoring device 24 can also monitor a size counter 28 having an emitter unit 29a and a detector unit 29b. As a non-limiting example, the emitter unit 29a can emit ultrasonic waves 30 that are received by the detector unit 29b. Thus, the relative movement of the shuttle 23 can be monitored with high precision to characterize drill string operations that affect drill string length. It should be appreciated that, in another embodiment, a laser beam can be used to monitor changes in the relative position of the shuttle 23. In this latter embodiment, a laser emitter/detector pair can be positioned at 29a while a reflector is positioned at 29b. By tracking the status of the clamp monitor 26 in conjunction with the movement of the shuttle 23, the length of the drill string 16 can be determined with, for example, a fraction of an inch accuracy. Specifically, when the shuttle engages the uphole end of the drill string and the clamp monitor indicates that the drill string is not clamped, the length of the drill string changes in response to the movement of the shuttle. The rig monitoring device 24 may also monitor a pressure sensor and flowmeter 31, which senses the pressure and flow of drilling fluid or mud, which may be pumped down the drill string at relatively high pressure, as described below. In some embodiments, a mud pump 32, used to pump drilling mud/drilling fluid down the drill string, may also be monitored by the rig monitoring device 24. Another sensor that may be monitored by the rig monitoring device 24 includes at least one gas detector 33, which may be configured to detect certain gases being emitted near the drill rig, such as from a pit through the ground or from the uphole end of the drill string, as will be further described in connection with cross-hole detection. In this regard, it should be noted that the gas detectors may be configured to detect natural gas and other forms or types of gases, such as sewer line gas, alone or in any suitable combination.

Each drill pipe segment defines a through opening 34 (one of which is shown) extending between opposite ends of the segment. The drill pipe segments can be equipped with what are commonly referred to as box-and-pin fittings so that each end of a given drill pipe segment can be threadedly engaged with an adjacent end of another drill pipe segment in a drill string in a known manner. Once the drill pipe segments are joined to form the drill string, the through openings of adjacent drill pipe segments align to form an integral passageway 36, as indicated by the arrows. Passageway 36 can provide for the pressurized flow of drilling fluid or mud from the drill rig to the drill bit in the direction of arrow 36, as will be described further.

The position of the drill tool within the area 12 and the subsurface path followed by the drill tool may be set and displayed at the drilling rig 14, for example on a console 42 using a display 44. The console may include processing means 46 and control actuator means 47.

The drilling tool 20 may include a drill bit 50 having an inclined surface for steering based on a roll orientation. That is, when the drill bit is advanced without rotation, it typically deflects based on the roll orientation of the drill bit's inclined surface. On the other hand, by rotating the drill string as indicated by the double arrow 51 while the drill bit is being advanced, the drill bit can typically be directed in a straight line. Of course, predictable steering is conditional on suitable soil conditions. It should be noted that the aforementioned drilling fluid may be ejected under high pressure as a jet 52 to penetrate the ground directly in front of the drill bit and provide cooling and lubrication for the drill bit. The drilling tool 20 includes an inground housing 54 that houses an electronics package 56. The inground housing is configured to allow the drilling fluid to flow around the electronics package to the drill bit 50. For example, the electronics package may be cylindrical and centrally supported within the housing 54. The drill bit 50 may include a box fitting that receives a pin fitting of the inground housing 54. Opposite ends of the inground housing may include box fittings that receive the pin fittings of the coupling adapter 60. Opposite ends of the coupling adapter 60 may also include box fittings that receive the pin fittings that define the inground distal end of the drill string. It should be noted that the drill bit, inground housing, and box fittings of the coupling adapter are typically identical to those provided on the drill pipe segments of the drill string, so that the drill pipe segments can be removably attached to one another when forming the drill string. The inground electronics package 56 may include a transceiver 64. In some embodiments, the transceiver 64 may transmit a positioning signal 66, such as a dipole positioning signal, although this is not required. In some embodiments, the transceiver 64 may receive electromagnetic signals generated by other inground components and/or surface components, as will be described at appropriate locations below. For descriptive purposes, this example assumes that the electromagnetic signal is a positioning signal in the form of a dipole signal. Therefore, the electromagnetic signal may be referred to as a positioning signal. It should be appreciated that a dipole signal can be modulated like any other electromagnetic signal, and the modulated signal can be later recovered from the signal. The signal's locating function depends, at least in part, on the characteristic shape of the magnetic flux field and its signal strength, rather than its ability to be modulated. Therefore, modulation is not required. Information about certain parameters of the drill tool, such as pitch and roll (orientation parameters), temperature, and drilling fluid pressure, can be measured using appropriate sensor devices 67 located within the drill tool or any in-ground tool being used. Sensor devices 67 may include, for example, a pitch sensor, a roll sensor, a temperature sensor, an AC field sensor for sensing the proximity of a 50/60 Hz utility line, and any other sensors required, such as a DC magnetic field sensor for sensing yaw orientation (a three-axis magnetometer with a three-axis accelerometer to form an electronic compass for measuring yaw orientation). Another parameter of interest may be the depth of the in-ground tool, as determined by the locator based on signal 66. Any suitable protocol may be used to communicate parameters from the drill tool to the drilling rig. For example, a data packet protocol may be used, wherein a series of data packets, including data packets specific to each parameter of interest, are transmitted from the locator. These data packets may be in the form of pitch packets, roll packets, depth packets, and so on. This data packet protocol may be employed throughout the system to communicate any parameter of interest. Pressure sensors in inground tools can sense fluid pressure in the annular region surrounding the drill bit or in other downhole components, such as reaming equipment used in utility pullback operations. As a non-limiting example, one suitable embodiment of such a pressure sensing device is disclosed in U.S. Application No. 13/071,302, filed by the same applicant as the present application and incorporated herein by reference in its entirety. In some embodiments, sensor assembly 67 can include a gas sensor configured to detect natural gas and/or any other gas of interest in the annular region surrounding the borehole in response to, for example, contact of the drill tool with a cross-hole 68 in the form of a borehole, as will be further described. In this regard, it should be noted that the gas sensor can be configured to detect other forms or types of gas, such as sewer/wastewater line gas. Another sensor that can be used for cross-hole detection during pilot hole formation is a force sensor, which can measure the force applied by the drill bit to the ground as the drill string is driven underground by the drill rig, as will be further described. Electronics package 56 also includes a processor 70 that interfaces with sensor assembly 67 and transceiver 64 as needed. Another sensor that can form part of the sensor assembly is an accelerometer configured to detect acceleration along one or more axes. A battery (not shown) can be provided within the housing to generate power. The electromagnetic signal 66 can be detected using a portable device 80, such as a portable lightweight locator. A suitable and highly advanced portable locator is described in U.S. Patent No. 6,496,008, entitled "FLUX PLANELOCATING IN AN UNDERGROUND DRILLING SYSTEM," filed by the same applicant as the present application, the entire contents of which are incorporated herein by reference. While the description is presented in the context of horizontal directional drilling, as described above, the present invention is applicable to a variety of underground operations and is not intended to be limiting. As described above, the electromagnetic signal can carry information including orientation parameters such as pitch and roll. The electromagnetic signal can also carry other information. For example, such information can include parameters that can be measured near or within the drill string, including temperature and voltages such as battery or power supply voltage. The locator 80 includes an electronics package 82. It should be noted that the electronics package is connected for electrical communication with the various components of the locator and can perform data processing. Information of interest can be modulated onto electromagnetic signal 66 in any suitable manner and transmitted to antenna 84 at the locator 80 and/or the drill rig, although this is not required. The locator electronics package 82 can include a telemetry transceiver for transmitting locator telemetry signals 92 via antenna 94, which can be received by the drill rig using antenna 84. Any suitable form of modulation, currently available or yet to be developed, can be used. Examples of currently available and suitable types of modulation include amplitude modulation, frequency modulation, phase modulation, and variations thereof. When the locating signal is recovered, any parameter of interest related to the drilling operation, such as pitch, can be displayed on display 44 and/or on display 86 of the locator 80. The drill rig 14 can transmit telemetry signals 96 that can be received by the locator 80. Thus, two-way telemetry communication and signal transmission can be established between antenna 84 at the drill rig and antenna 94 at the locator. As an example of such signaling, based on the status provided by the drill rig monitoring unit 24, the drill rig can transmit an indication that the drill string is at rest because a drill pipe segment is being added to or removed from the drill string. The locator 80 can also include an inground communication antenna 98, such as a dipole antenna, for bidirectional reception of inground communication signals 99, with the antenna 98 being arranged in electrical communication with the transceiver device in the electronics portion 82. Thus, bidirectional signaling and communication is established between the locator 80 and the transceiver 64 of the inground tool via the antenna 98. As will be seen, this arrangement establishes a highly advantageous communication loop from the locator 80 to the inground tool 20 and up the drill string 16 to the drill rig.

Still referring to FIG. 1 , a cable 100 can extend from the inground electronics package 56 so that any sensed values or parameters related to the operation of the inground tool can be electrically transmitted over the cable. Those skilled in the art will recognize that a device commonly referred to as a "wire-in-pipe" can be used to transmit signals to the drill rig. The term "wire-in-pipe" refers to a cable housed within the internal passageway 36 formed by the drill string. However, according to the present invention, the cable 100 extends to an inground coupling adapter 60, which will be described further below.

Reference is now made to FIG. 2 in conjunction with FIG. 1 . FIG. 2 is a schematic perspective view illustrating one embodiment of a coupling adapter 60 in further detail. Specifically, the coupling adapter includes a body 120 having a pin fitting 122 formed therein for engaging with a box fitting (not shown) of the inground housing 54 . Note that, for clarity, the threads on the pin fitting are not shown, but it should be understood that they are present. The body includes at least one high-voltage electrical connection assembly 130, which will be described in further detail at one or more appropriate points below. The coupling adapter 60 also includes an extension 140 that is removably attached to the body 120 to enable replacement of the body or extension. The body and extension can be formed from any suitable material, such as non-magnetic alloys including non-magnetic stainless steel, and magnetic alloys such as 4140, 4142, 4340, or any suitable high-strength steel. In particular, a non-magnetic form may not be required when the coupling adapter is positioned many feet or multiple drill pipes away from the electronics module that drives the coupling adapter. However, if the coupling adapter is used near in-ground equipment, such as a guidance tool that detects the Earth's magnetic field, using a non-magnetic material can avoid potential field interference. In this regard, it is well known that non-magnetic high-strength alloys are generally much more expensive than their magnetic counterparts. It should be noted that the main body and extension body do not need to be formed from the same material.

A cylindrical ring 144 is housed between the main body 120 and the extension 140. The cylindrical ring can be formed from any suitable material that is substantially resistant to the underground environment and electrically insulates. As a non-limiting example, one suitable material is phase-transformation toughened zirconia ceramic, although other ceramic materials may also be suitable. As shown in FIG2 and other figures yet to be described, to reduce the potential for damage to the cylindrical ring and reduce wear on the cylindrical ring, the outer surface 145 of the cylindrical ring 144 can be recessed relative to the outer surfaces of both the main body and the extension. For example, due to the recessed shape of the cylindrical ring and when the clamp (not shown) is properly engaged with the coupling adapter, a clamp holding the pipe section at the drilling rig can bridge over and maintain contact with the cylindrical ring. Furthermore, underground wear on the cylindrical ring caused by rotation, advancement, and retraction of the drill string can be reduced. In this regard, it should be appreciated that, for similar reasons, the electrical connection assembly 130 can also be recessed, as shown in FIG2 and other figures yet to be described.

With reference to Figures 2 to 4, further details of the structure of the coupling adapter 60 will now be provided. Figure 3 is a schematic exploded perspective view of the coupling adapter, while Figure 4 is a schematic partially cutaway exploded front view of the coupling adapter. The main body 120 includes an attachment end 150 that is threaded and threadedly engaged with a threaded receiving portion 152 defined by the extension body 140. It should be appreciated that threaded engagement is not required, and the extension body can be attached to the main body using any suitable technique, including but not limited to the use of fasteners, adhesives, and splines with spiral pins. It should be appreciated that such attachment withstands the full torque, thrust, and pull forces of any in-ground operation to which it is subjected. When using a threaded embodiment, before torquing the coupling, to further ensure that the connection will not loosen, an epoxy resin or a thread locking compound such as a methacrylate adhesive or a waterproof commercial thread locking compound can be applied. In one embodiment, the pin of the male thread is designed to bottom out as soon as the shoulder contacts, which is known in the related art as a double shoulder design.

The current transformer 160 is configured to be mounted within a transformer recess or groove 162 defined by the main body 120. The current transformer comprises a coil wound around an annular or toroidal core. In this regard, the core may comprise any suitable cross-sectional shape, such as rectangular, square, and circular. In the illustrated embodiment, the core may be split to facilitate mounting of the current transformer within the transformer recess 162. A pair of electrical leads 164 terminate at opposite ends of the current transformer coil to form external electrical connections, to be described. It should be appreciated that any suitable current transformer may be used and that the specific current transformer described herein is not intended to be limiting. The opposite end 170 of the extension body 140 defines a box fitting 172 for threaded engagement with the buried distal end of the drill string. With reference to FIG. 1 , it should be appreciated that when assembling the drill string at the drilling rig, the coupling adapter 60 may be installed between any two adjacent drill pipe segments. For example, the coupling adapter 60 may be located between drill pipe segments n-1 and n in FIG. 1 . The cable 100 then extends from the inground tool through the drill pipe section n to the coupling adapter.

Referring to Figures 5 and 6 in conjunction with Figures 2-4, Figure 5 is a partially cutaway front elevational assembled view of coupling adapter 60, while Figure 6 is a further enlarged partially cutaway assembled view of the portion taken within circle 6-6 in Figure 5. When assembled as shown in Figure 6, O-ring 178 can be used to form a seal between body 120 and the inner surface of cylindrical ring 144, while O-ring 180 is used to stabilize the ceramic ring and limit direct contact with flange 182 of extension body 140, for purposes yet to be described. O-ring 180 can contact the ceramic ring, flange 182, and sidewall 184 of body 120. As shown in Figure 5, the components of coupling adapter 60 are assembled to collectively define a passageway 190, which is used to direct drilling fluids as part of or in conjunction with the drill string when the inground tool requires such fluids. Based on the double-shoulder structure ( FIG. 5 ) including the first shoulder 186 and the second shoulder 188, the main body 120 and the extension 140 can achieve a pressure seal between the main body 120 and the extension 140 when assembled, so that drilling fluid cannot leak from between the main body and the extension, even when the drilling fluid is under high pressure. In addition, a suitable sealing compound such as an epoxy compound can be applied to the threads between the shoulders 186 and 188 to provide additional sealing.

With reference primarily to FIG6 in conjunction with FIG4 , attention will now turn to the details of one embodiment of the high-voltage electrical connection assembly 130. In this regard, it should be noted that the high-voltage electrical connection assembly is shown in exploded view in FIG4 and in assembled view in FIG6 . To electrically connect to the current transformer 160, the high-voltage electrical connection assembly is disposed within a stepped aperture 200 defined in the sidewall of the main body 120. The connection assembly includes a lower insulator 204 defining a groove within which an O-ring 206 is received to seal the lower insulator relative to the stepped perimeter of the aperture 200, thereby preventing leakage of pressurized fluid during use, for example, during drilling operations. The overall shape of the lower insulator 204 is that of a cup with a central opening in the bottom. The lower insulator can be formed from any suitable electrically insulating material capable of withstanding the sometimes harsh underground environment. Such suitable materials include, but are not limited to, high-performance polymers that are not electrical conductors. The cavity within the cup defined by the lower insulator receives a power pin 210, which can be sealed relative to the lower insulator using an O-ring 212. The power pin defines a central bore 214. The power pin can be formed of any suitable electrically conductive material capable of withstanding the sometimes harsh underground environment. Such materials include, but are not limited to, electroless nickel-plated beryllium copper or phosphor bronze. The distal end 216 of the cable 100 is received in the central opening of the lower insulator 204 and positioned within the central bore 214 of the power pin 210. A set screw 220 is threadedly engaged with the sidewall of the power pin and extends into the central cavity 214, thereby engaging the distal end 216 of the cable in a manner that electrically connects the power pin to the cable 100 and retaining the distal end 216 of the cable within the power pin. In addition to the use of a set screw 220, any suitable structure can be used to retain the distal end of the cable within the power pin and electrically connect the two.

Still referring to Figures 6 and 4, the upper insulator 240 is received in the stepped hole 200 and is sealed relative to the stepped hole 200 using one of the O-rings 206. For purposes to be explained below, a set screw 242 can be threadedly engaged with the upper insulator. The upper insulator 240 can be formed from any suitable material, including those materials that can form the lower insulator 204. The set screw 242 is installed before the upper insulator 240 is installed and can be accessed by removing the upper insulator. The upper insulator can be defined with an opening 246 for the purpose of facilitating removal of the upper insulator, such as by accommodating the threaded end of a pulling tool. A cover 260 is received so as to rest against the upper step of the stepped hole 200 and can be held in place, for example, by means of a threaded fastener 262 (Figure 4). The cover can be formed from any suitable material, including but not limited to steel. One suitable material that has been found to be heat-treated 17-4 steel. As shown in FIG. 6 , to reduce wear and avoid contact with a clamping mechanism at the drill, the outer surface of the cover 260 may be concave relative to the outer surfaces of both the main body and the extension.

As described above, the current transformer 160, for example, using a split annular core 270, is housed in the annular groove 162. Leads 164a and 164b extend from the coil 272 of the current transformer. The lead 164a is locked in place by a set screw 276 to be electrically connected to the main body 120. The lead 164b extends through the internal passage 280 defined by the main body 120 and leads from the annular groove 162 to the stepped hole 200. The end of the lead 164b is locked in place by a set screw 242 to be electrically connected to the power pin 210, so that the current transformer lead 164b is electrically connected to the cable 100. Any suitable structure can be used to form the electrical connection between the lead 164b and the power pin. The design of the current transformer should pay attention to at least the following points:

1. Shock and vibration. Material selection and construction should be able to withstand the shock and vibration of the downhole drilling environment.

2. The selection of magnetic materials should be based on low core loss, high flux saturation and mechanical strength at the operating frequency.

3. High magnetic flux saturation allows the cross-sectional area of the core to be reduced to increase the cross-sectional area of the adapter coupling body for torque and power transmission.

4. Low inter-winding capacitance for high frequency response.

With the foregoing in mind, in one embodiment and by way of non-limiting example, a tape wound core may be used. As is well known to those skilled in the art, such cores are less susceptible to shock and vibration than ferrite cores. Such tape wound cores may be manufactured using thin, high flux saturation tape to avoid eddy current losses in the core. In some embodiments, the tape thickness may range from 0.00025" to 0.001". A suitable thickness is 0.0007". The tape wound core may be finished, for example, using a powder coating or epoxy coating. In one embodiment, additional vibration and shock protection may be provided to the current transformer and its core based on the manner in which the current transformer is mounted in the recess 162.

A current transformer can use a single-turn secondary winding in the form of a drill pipe and surrounding soil to create a complete current path. With the drill pipe itself serving as the single-turn secondary winding, the current transformer's primary winding can convert the low current output from the driver electronics into a high-current signal on the drill pipe. The terms primary and secondary are, of course, interchangeable based on the direction of signal coupling and are used here for descriptive, non-limiting purposes. The current ratio is proportional to the number of turns in the primary winding. For example, ignoring magnetic and resistive losses, if the current entering the primary winding is 10 mA and the primary-to-secondary turns ratio is 100/1, the resulting current induced on the drill pipe will be 1000 mA, one hundred times the input current. As mentioned above, the tape-wound core can be encapsulated in epoxy resin using any suitable thermoplastic or epoxy resin for increased mechanical strength. For installation purposes, the finished core or toroid can be cut into two core halves, for example using a diamond saw, and the transformer winding can be applied to each core half. A magnetic gap can be created by forming a small gap, e.g., about 0.001", between the facing surfaces of the core halves by bonding a piece of non-magnetic material (e.g., mylar, a strong polyester film) between the facing surfaces. This gap helps prevent magnetic saturation of the core. As is known in the art, the cross-section of the core can be determined using the frequency, flux density, number of turns of magnetic wire (e.g., insulated copper wire), saturation flux density, and voltage applied to the current transformer. For frequencies from a few kilohertz to a hundred kilohertz, for example, the cross-section can be about 0.2" x 0.2". In some embodiments, the current transformer is mounted in the adapter recess in a manner that can withstand shock.

The embodiment shown in FIG6 can be assembled, for example, by first installing the current transformer 160 into the annular groove 162. The cable 100 can be extended into the passage 190 of the main body and out of the stepped hole 200. The lower insulator 204 can then be installed onto the cable 100 by tightening the set screws 220, such that the power pin 210 is mounted to the distal end of the cable. As shown in FIG6, the power pin can be received within the stepped periphery. The current transformer lead 164b can be threaded through the passage 280, positioning the distal end of the lead 164b as shown in FIG6. The upper insulator 240 can then be installed and the set screws 242 tightened. The cover 260 can then be installed. The installation of the current transformer lead 164a and the cylindrical ring 144 is straightforward. It should be appreciated that in practice, the current transformer, cylindrical ring, and high-voltage electrical connection assembly are easily replaceable/repairable.

Referring to FIG. 7 a , another embodiment of a coupling adapter according to the present invention is generally designated by reference numeral 60 ′ and is shown in a partial cross-sectional view. For the sake of brevity, the description of the components identical to those shown in the previous figures will not be repeated. The difference between this embodiment and the previous embodiments lies primarily in the construction of an electrical connection assembly 130 ′, which is part of a modified body 120 ′, as will be described in detail below.

Turning to Figures 7b and 7c in conjunction with Figure 7a, a modified power pin 210' is provided. Figure 7b is a partially cutaway front exploded view, while Figure 7c is a front and partially cutaway view of a portion taken within circle 7c-7c shown in Figure 7b. In this embodiment, the modified power pin 210' is configured to support a coaxial connector assembly 300 including a coaxial plug 302 and a coaxial receptacle 304. Although Figure 7c shows the plug 302 and receptacle 304 unconnected for clarity, it should be understood that the plug and receptacle mate together for operation of the assembly. Current transformer leads 164a, 164b extend through internal passage 280 and are electrically connected to a pair of terminals 310 of receptacle 304. Electrical conductors 312a, 312b from cable 100 (which, in this embodiment, may be a coaxial cable) are electrically connected to a pair of terminals 320 of plug 302. It should be noted that some components, such as the upper insulator 240, may be slightly modified to accommodate the coaxial connector assembly 300; however, such minor modifications are considered within the capabilities of one of ordinary skill in the art, given the overall disclosure of the present invention. It should be appreciated that the electrical connection from the cable 100 to the current transformer 160 remains electrically isolated from the adapter body, and thus from the drill string itself. This isolation reduces common-mode noise that can be coupled to the drill string due to 50 Hz or 60 Hz ground currents and noise present in buried environments.

In view of the foregoing, it will be appreciated that in some cases, for example, when the sidewall thickness of the drill pipe segment is sufficient to define a support recess for the current transformer without unduly weakening the drill pipe segment, the drill pipe segment can be configured to support the current transformer in a manner consistent with the above description. Furthermore, given the entire disclosure of the present invention, one of ordinary skill in the art will appreciate that a drill pipe segment having sidewalls of sufficient thickness can support the aforementioned electrical connectors, passages, and assemblies with limited or no modification.

FIG8 is a schematic perspective view of inground tool 20 in the form of a drill having drill bit 50. In this embodiment, inground housing 54 includes slot 400 for transmitting signal 66 from transceiver 64 ( FIG1 ). Coupling adapter 60 is removably attached to inground housing 54, which itself is provided for removable attachment to the distal end of a drill string.

FIG9 is a schematic perspective view of an inground tool 20 in the form of a reaming tool, including an underreamer 420 removably attached to one end of an inground housing 54. Additionally, in this embodiment, the housing 54 and coupling adapter 60 are arranged in the same manner as in FIG8 . To reame the hole while the underreaming tool is pulled toward the drill rig by the drill string, the underreaming tool is pulled in the direction indicated by arrow 422. The opposite end of the underreaming tool is attached to one end of a tension monitoring device 430. The opposite end of the tension monitoring device can be attached to a utility (not shown) that will be pulled through the enlarged borehole to install the utility in the borehole. During the reaming operation, the tension monitoring device 430 measures the tension applied to the utility. A suitable and highly preferred tension monitoring device is described in U.S. Patent No. 5,961,252, filed by the same applicant as the present application, the entire contents of which are incorporated herein by reference. The tension monitoring device 430 is capable of transmitting an electromagnetic signal 434 that can modulate tension monitoring data. In an embodiment, the tension monitoring device 430 is capable of sensing the surrounding downhole pressure and modulating the pressure data onto a signal 434. The transceiver 64 ( FIG. 1 ) can receive the signal 434 so that the corresponding data can be placed on the drill string using a current transformer 160 (see FIG. 3 to FIG. 6 ) for transmission to the drilling rig. It should be appreciated that the transceiver 64 is capable of receiving wireless signals from any type of inground tool, and that the present embodiment of the tension monitoring device described is not intended to be limiting. For example, a survey device can be used in place of the tension monitoring device in another embodiment. Such a survey device can be operated, for example, using an inertial navigation system (INS). It should also be appreciated that the portable device 80 can be used to detect the signal 434 so that the recovered data can be transmitted to the drilling rig or any other suitable surface component of the system via the telemetry signal 92.

FIG10 is a block diagram illustrating one embodiment of an electronics section (generally designated 500) that may be supported within inground housing 54. Section 500 may include an inground digital signal processor 510 that facilitates all of the functionality of transceiver 64 and processor 70 of FIG1 . Sensor section 67 is electrically connected to digital signal processor 510 via analog-to-digital converter (ADC) 512. Any suitable combination of sensors may be provided for a given application, and may be selected, for example, from an accelerometer 520, a magnetometer 522, a temperature sensor 524, a pressure sensor 526 capable of sensing the pressure of drilling fluid in the area surrounding the inground tool, and a gas sensor 528 configured to detect any desired form of gas, such as natural gas, propane, other hydrocarbon gases, and/or sewer gas. The gas sensor may be of any suitable type currently available or yet to be developed. A force sensor 529 may measure the force generated during drilling operations in response to the drill bit being forced against the soil in front of it. The sensor may be disposed in any suitable manner, and may even be disposed in an adapter or housing mounted in the drill string behind the inground housing 54. For example, a force sensor may be mounted in the adapter 60. As non-limiting examples, embodiments of the force sensor may utilize strain gauges, piezoelectric sensors, and other commonly used load cell technologies.

Current transformer 160 can be connected for either or both a transmit mode, in which data is modulated onto the drill string, and a receive mode, in which the modulated data is recovered from the drill string. For the transmit mode, the antenna is driven using an antenna driver section 530 electrically connected between the in-ground digital signal processor 510 and current transformer 160. Typically, the data coupled into the drill string can be modulated using a frequency different from any frequency used to drive dipole antenna 540 (capable of transmitting the aforementioned signal 66 ( FIG. 1 )) to avoid interference. When antenna driver 530 is off, a switch (SW) 550 selectively connects current transformer 160 to a bandpass filter (BPF) 552 having a center frequency corresponding to the center frequency of the data signal received from the drill string. BPF 552, in turn, is connected to an analog-to-digital converter (ADC) 554, which itself is connected to digital signal processing section 510. The recovery of the modulated data in the digital signal processing section can be easily configured by one of ordinary skill in the art, taking into account the specific form of modulation employed.

Still referring to FIG. 10 , dipole antenna 540 can be connected for either or both a transmit mode, in which signal 66 is transmitted into the surrounding earth, and a receive mode, in which electromagnetic signals, such as signal 99 (see also FIG. 1 ) and/or signal 434 of FIG. 9 , can be received. For the transmit mode, the antenna is driven by an antenna driver section 560 electrically connected between the in-ground digital signal processor 510 and dipole antenna 540. Furthermore, the frequencies of signals 66 and 99 are typically sufficiently different from the frequencies of drill string signals to avoid interference between the two. When antenna driver 560 is off, a switch (SW) 570 selectively connects dipole antenna 540 to a bandpass filter (BPF) 572 having a center frequency corresponding to the center frequency of the data signal received from the dipole antenna. BPF 572, in turn, is connected to an analog-to-digital converter (ADC) 574, which itself is connected to the digital signal processing section 510. Depending on the particular form or forms of modulation employed, and in view of the overall disclosure of the present invention, one of ordinary skill in the art will be able to readily construct transceiver electronics for the digital signal processing portion in many suitable embodiments.

Referring to FIG. 1 and FIG. 11 , FIG. 11 is a block diagram of components that may constitute one embodiment of a surface transceiver device (generally designated by reference numeral 600) coupled to a drill string 16. A surface current transformer 602 is located, for example, on the drill rig 14 to couple and/or receive signals from the drill string 16. The current transformer 602 may be electrically connected for use in one or both of a transmit mode, in which data is modulated on the drill string, and a receive mode, in which the modulated data is recovered from the drill string. A transceiver electronics package 606 is connected to the current transformer and may be powered by a battery. For the transmit mode, the current transformer is driven using an antenna driver portion 610 electrically connected between a surface digital signal processor 620 and the current transformer 602. Furthermore, as shown in FIG1 , the data coupled into the drill string can be modulated using a frequency different from one or more of the frequencies used to drive the dipole antenna 98 in the portable locator and the antenna 540 in the inground housing 54, to avoid interference and to avoid being at a frequency different from the frequency at which the current transformer 160 ( FIG10 ) couples the signal into the inground end of the drill string. When the antenna driver 610 is off, a switch (SW) 620 can selectively connect the current transformer 602 to a bandpass filter (BPF) 622 having a center frequency corresponding to the center frequency of the data signal received from the drill string. The BPF 622 is in turn connected to an analog-to-digital converter (ADC) 630, which is itself connected to a digital signal processing section 620. It should be appreciated that the digital signal processing section 620 and associated components can form part of the drilling rig's processing unit 46 (shown using dashed lines) or be connected thereto via a suitable interface 632. The transceiver 606 can send commands to the inground tool for various purposes, such as controlling the transmit power, selecting the modulation frequency, changing the data format (e.g., reducing the baud rate to increase the decoding range), etc. Depending on the specific form or forms of modulation employed, and in light of the overall disclosure of the present invention, one of ordinary skill in the art will be able to readily construct transceiver electronics for the digital signal processing portion in many suitable embodiments.

Referring to FIG. 1 , in another embodiment, another coupling adapter 60 and another example of an in-ground housing 54 or 54 ′ are shown, wherein a current transformer 160 connected to a transceiver 606 ( FIG. 11 ) is inserted as a unit into a joint in a drill string, thereby serving as a repeater 1,000 feet from an in-ground tool. The repeater unit can be inserted into the joint formed between drill pipe segments 1 and 2 in FIG. 1 . The in-ground housing for repeater applications can include a box fitting at one end and a pin fitting at the opposite end. Of course, those skilled in the art will recognize that box-and-pin fitting adapters are known and readily available. In another embodiment, the coupling adapter 60 can be inserted into the joint, while the repeater electronics are housed in a pressure barrel, which can be supported by a centralizer within the channel of an adjacent drill pipe segment. In another embodiment, the repeater electronics can be housed in an end- or side-loaded housing, inserted into the drill string, and in electrical communication with the coupling adapter. Such an end-loaded or side-loaded housing may include a passageway that allows drilling fluid to flow therethrough. Of course, in any of these embodiments, the repeater electronics may be electrically connected to the current transformer of the coupling adapter in a manner consistent with the above description. To avoid signal interference, and as a non-limiting example, the current transformer may acquire a signal originating from the inground tool or another repeater at one carrier frequency, and the repeater electronics may retransmit the signal from the current transformer up the drill string at a different carrier frequency so that the received signal is distinguishable from the repeater signal coupled back to the drill string. As another example, suitable modulation may be used to make the repeater signal distinguishable from the received signal. Thus, the repeater electronics package is housed in the housing cavity of the inground housing and is in electrical communication with the signal coupling device of the coupling adapter to generate a repeater signal that is distinguishable from the received data signal based on the received data signal. The repeater signal is provided to a signal coupling device so that the signal coupling device electromagnetically couples the repeater signal back to the drill string to transmit the repeater signal as another electrical signal along the drill string so as to electrically conduct the repeater signal using at least some of the conductive drill pipe sections that constitute different portions of the drill string.

1 and 9, as described above, during the various drilling operations of FIG1 and the pullback operation shown in FIG9, drilling fluid may be pumped downhole along passage 36, and the pullback operation may utilize an underreamer 420 that pulls a utility (not shown) uphole in the direction of arrow 422 through a pilot hole 700, partially shown and indicated by a dashed line in FIG9. It will be appreciated that, as described with respect to FIG1, the underreamer 420 may also be configured to discharge drilling fluid, for example, in the form of a jet 52.

One problem associated with the above-described underground drilling operations is the risk associated with striking existing underground utilities. In the context of the present invention, such existing utilities may be interchangeably referred to as cross-bores. Unfortunately, even if every reasonable precaution is taken to avoid striking a cross-bore, such as utilizing utility company information to identify the location of underground utilities and utilizing any available utility maps at the worksite for drilling planning, the possibility of striking a cross-bore still exists, at least due to the potential presence of unknown utilities. FIG1 illustrates this scenario, where, for this example, the drill string 20 has struck a cross-bore 68 of a hypothetical, but unknown, sewer line. As shown in FIG1 , the drilling fluid jet 52 is being injected directly into the sewer line. Unfortunately, these situations are difficult for the operator of the drilling rig 14 to detect, at least because the transit time through the cross-bore 68 can be very short. Subsequently, during the pullback operation to install the utility in the pilot hole 700 of FIG9 , the reamer and utility line may rapidly pass through the cross-bore. Ultimately, the result may be that the new utility line passes directly through an existing utility line, such as a sewer line, which will significantly block the sewer line. Subsequent work to clear the sewer line may result in cutting off or at least damaging the new utility. The consequences of such damage can be severe. For example, if the new utility is a gas line, damage to the gas line may create a path for natural gas to flow directly into the structure. In some cases, as shown in Figure 9, the cross-hole 704 may be located outside the pilot hole 700 so that the drill string will not hit the cross-hole, but the cross-hole is close enough to be contacted by the reaming tool 420, thereby creating a flow path from the annular area around the reamer directly into the cross-hole. Figure 9 shows a particular jet 52' being injected directly into the cross-hole 704. In some cases, contact between the reamer and the cross-hole may occur due to a condition known as "keyhole," in which the utility pullback tends to straighten a curve that may have been intentionally formed in the pilot hole. In any case, the result may be an undesirable intersection between the new utility and an already existing utility.

Referring to FIG. 9 , another issue with drilling fluids involves what is commonly referred to as frac leaks. Frac leaks can occur during drilling or reaming operations, where drilling fluid 710 leaks as indicated by the arrows, forming puddles or pools 714 on the ground. In some cases, bubbles form that at least temporarily elevate the ground surface. Issues with frac leaks can involve contamination and/or damage to existing ground structures, such as roads and sidewalks, caused by drilling fluid mixed with groundwater.

The present invention discloses lightweight systems, apparatus, and related methods for detecting at least potential cross-hole contact and fracturing leak conditions. By making operators aware of these conditions, the operators can take appropriate actions, such as cave surveys, to confirm the presence of potential cross-holes and initiate appropriate preventative measures and repairs as needed.

With reference to Figures 1, 10, and 11, applicants have recognized that certain conditions are at least potentially indicative of cross-hole and/or frac leak conditions and can be monitored based on these figures. In some cases, specific types of information are useful in attempting to distinguish between these two conditions, however, both conditions are of concern to system operators. As will be seen, this determination can be made based on a combination of information and data that can be collected from downhole, uphole, and surface sources.

Attention is now directed to FIG. 12 a, which illustrates an embodiment of a method, generally designated 900, for monitoring various parameters, the combination of which may indicate a potential cross-hole and/or fracturing leak condition. The method begins at a start step at 902 and proceeds to step 906, which may initiate system monitoring, including monitoring by the drill rig monitoring device 24 ( FIG. 1 and FIG. 11 ). The drill rig monitoring device may collect information from the various sensor devices shown in FIG. 11 , including, but not limited to, uphole mud pressure, mud flow, drill string length based on the motion of the drill rig shuttle and the status of the drill string clamps, and any other measurable parameters of interest at the drill rig. Other parameters transmitted from the inground tool via the drill string may be received, for example, by the console 42 ( FIG. 1 ). Such downhole parameters include, but are not limited to, downhole pressure sensed by pressure sensor 526 ( FIG. 10 ), temperature sensed by temperature sensor 524 , indications generated by gas detector 528 , orientation parameters from accelerometer 520 , readings from magnetometer 522 , and any other measurable downhole parameters of interest. It should be appreciated that system 10 is capable of rapidly updating and transmitting these measured parameters up the drill string to console 42 , thereby providing essentially real-time monitoring, at least from an operator's perspective and from a practical standpoint. For example, pressure signals from downhole pressure sensor 526 may be transmitted at a frequency of at least once per second. Simultaneously, other information may also be collected from portable locator 80 . For example, the portable locator may determine the current depth of the inground tool and transmit the depth or related information to the drill rig via telemetry signal 92 . As described above, the telemetry signal may utilize a packet protocol for transmitting depth and other types of data packets. Data packets received by the portable locator from the inground tool (e.g., pitch and roll data packets) may be forwarded to the drill rig via the telemetry signal.

Referring to FIG. 1 in conjunction with FIG. 12a , in the context of method 900 and/or with respect to other techniques, data generated at a portable locator or other surface device can be sent directly to an inground tool via communication signal 99, and then transmitted up the drill string via processor 70 and coupling adapter 60 to a control station 42 at the drill rig. Any signal obtained at locator 80 can be transmitted via this route, regardless of whether the underlying data is determined at the locator or elsewhere. As a non-limiting example, this inground communication link can be used to transmit depth readings or other signals to control station 42 via the inground tool. In this regard, operational situations may exist where telemetry signal 92 is lost, too weak to be reliable, or impractical, such as when drilling or backreaming under conditions that include line-of-sight obstructions, localized interference that may be passive and/or active, and, optionally or concurrently, drilling significant distances without the telemetry signal being strong enough for successful communication. In this regard, the output telemetry power threshold is typically regulated by the particular regulatory agency of the country. In such cases, communication via the underground communication link can be performed without regard to issues such as the intermittent, missing, or unavailable telemetry communication link. Monitoring of the various communication paths of the system will be described at one or more appropriate locations below. However, in this regard, it should be recognized that the present discussion related to the detection of fracturing leaks and/or cross-hole indication conditions is not limited to any particular communication route or mode for data transmission. For example, all data communications can be carried out in a manner that is sent from the underground tool to the locator 80 and from the locator 80 to the drill rig 14 via telemetry. Of course, such communication can be bidirectional. Regardless of the depth or other path taken by the signal to reach the drill rig, the data can be recorded and time-stamped at the console 42. Of course, the data can be recorded at any appropriate location as long as it is accessible, as will be discussed further.

Referring to FIG. 13 in conjunction with FIG. 12 a , FIG. 13 illustrates an embodiment of a data structure, generally designated 920, capable of recording any parameter of interest. The data structure may be stored and maintained, for example, in a console 42 at a drilling rig. In another embodiment, the data structure may be stored remotely, for example, in a cloud storage as primary storage and/or stored as a backup. In another example, the data structure may be stored in a portable device and/or in an in-ground tool. As non-limiting examples, the recorded parameters may include uphole mud pressure 922, downhole mud pressure 924, mud flow rate 926, mud pump status 928, drill string length 930, drill string push/pull rate 932, depth 934, pitch 936, position 938, uphole and downhole gas detector readings 940, pullback data 942, force data 944, and any other parameter of interest that may be characterized uphole, on the surface, underground, and/or downhole. As will be discussed further, force data can include the thrust applied by the drill rig to the uphole end of the drill string and the drill bit force applied by the drill bit to the soil in response to the thrust. It should be noted that some of these parameters can be derived from the input data using pre-processing in the console 42 (e.g., based on combined processing of uphole and downhole data before recording the values). Of course, for ease of reference, any basic or fundamental signal from which one or more other parameters can be derived can also be recorded. As shown in FIG13 , each input parameter is associated with an input denoted by the same reference numeral with an additional superscript. Turning again to the flowchart of FIG12 a , after step 906 , the operation proceeds to step 950 , which determines the current uphole mud pressure, e.g., the uphole mud pressure most recently measured by sensor 31 of FIG1 . In one embodiment, the current uphole mud pressure can be compared to an uphole threshold pressure. If the uphole mud pressure is below the threshold, the step is repeated in a loop. The uphole mud pressure threshold can be based on, for example, the soil and formation type, the size of the drill bit jet used, and/or the flow rate requirements of a given mud motor used downhole. Regarding the latter, a mud motor can be used to provide downhole rotation of an inground drill bit, as an alternative to rotating the entire drill string to rotate the drill bit. Such a mud motor is powered by mud pressure and flow rate to generate rotational torque. It should be appreciated that uphole mud pressure may not exist at certain times for various reasons, such as due to the addition or removal of drill pipe sections from the drill string. If the uphole mud pressure is detected to be at or above the threshold, the operation proceeds to step 952, which tests the current downhole mud pressure. In one embodiment, the current downhole mud pressure can be compared to a downhole mud pressure threshold. The downhole mud pressure threshold can be based on, for example, the pressure rating of the downhole tool, the electronics housing, the soil and formation type, the depth and distance from the drill rig, the mud weight, and the density and viscosity of the spoil (i.e., the combination of drill cuttings and drilling fluid traveling upward around the drill string). If the current downhole mud pressure is above the threshold, the operation can return to step 950. On the other hand, if the current downhole mud pressure is below the threshold, the operation can proceed to step 956, which can test the current flow rate, for example, compared to a threshold flow rate. The flow rate threshold can be based on, for example, requirements of the mud motor or drill bit related to advancement rate and borehole diameter. A flow rate value below the threshold causes the operation to branch to step 960, and can indicate that the operator should check for a clogged nozzle on the drill bit or some flow obstruction in the drill string. This indication can be audible and/or visual, for example, at one or both of the drill string console and the portable device 80. If the determination associated with step 960 is made at the drill rig console 42, the indication can be transmitted to the portable device 80 using telemetry signals 96 and/or using a subsurface communication loop, including down the drill string to the downhole electronics 500, which can then transmit the indication to the portable device 80 via signal 66. In this regard, it should be appreciated that any of these paths can provide two-way communication, and that when one path is unavailable, the other path can be used. Figure 14a is an embodiment of a screenshot, generally designated by reference numeral 962, which can represent the appearance of the display 44 on the drilling rig and/or the display 86 on the portable device, including a nozzle blockage indication. In an embodiment, operation of the drilling rig can be automatically paused until such a time as the operator rotates the input control to indicate that the mud flow problem has been resolved. Of course, monitoring can then be resumed. In this embodiment, the operator can choose to clear the warning and/or log the warning, but these various options can also be implemented in a variety of different ways. Any information of interest can be presented in conjunction with warnings including, but not limited to, downhole mud pressure, pitch, and drill string length.

If the mud flow rate is detected to be above the mud flow threshold in step 956, the operation proceeds to a data correlation step 970. This step may be configured according to various embodiments or may be optional in one embodiment. In another embodiment, the data correlation step may collect data from various sources relevant to the current operating conditions, such as an indication of a frac leak or cross-bore. For example, in response to steps 950, 952, and 956, data may be obtained from data structure 920 of FIG. 13 indicating the initial detection of a potential frac leak or cross-bore. The collected data may include uphole mud pressure, downhole mud pressure, and mud flow rate. Supplementary data for these parameters may be collected from times before and/or after the initial detection. In addition, any additional data of interest, such as drill string length and drill string push/pull rate, may be collected corresponding to selectable time intervals. In embodiments, the system may automatically determine and select the time interval. For example, the interval may be based on a first time point when downhole pressure initially decreases and a second time point when annular pressure recovers. The automatically selected interval may include an offset such that the interval begins before the first time point and ends after the second time point. At 974, a warning may be issued to the operator of the drilling rig and/or the operator of the portable device 80, visually using a suitable display and/or audibly. FIG14b is a screenshot of an embodiment of the appearance of a cross-hole warning, generally designated by reference numeral 976, while FIG14c is an embodiment of the appearance of a frac leak warning, generally designated by reference numeral 977. In each case, as a non-limiting example, the operator selection options and displayed data may conform to the options and data presented in FIG14a, although each screen may be customized in any suitable manner. As a non-limiting example, the various elements of the warning may include any suitable combination or combination of audible elements, tactile elements, and graphical displays of the current operational appearance, drill string status, and the location of a detected potential problem. In an embodiment, a graph of downhole mud annular pressure versus drill string length may be presented, for example, based on the relevant portion of data 924 of FIG13. In this regard, one or both of screens 976 and 977 may provide an option for generating and displaying a suitable graph. At 980, in one embodiment, a system operator may pause operations, for example, to investigate the current circumstances that led to the warning. In another embodiment, the operator may cancel the warning. In either case, operations may then proceed to step 984, which may save or transmit the records generated by data correlation step 970, for example, for reference and analysis purposes. In another embodiment, step 980 may automatically pause operations of the drilling rig. In addition to saving and transmitting the data records, the system may automatically initiate recovery procedures that may involve generating further information about the potential downhole anomaly. After operations are paused, the method may then end at 990. In another embodiment, step 990 may be configured to resume normal operations in response to the operator confirming that the problem has been resolved, for example, based on a cave survey or other suitable inspection.

Returning to the discussion of step 980, as long as the operation is not suspended, the system can continue monitoring at 994 by returning the operation to step 950. In this way, data collection associated with the current event will continue to perform the ongoing operation. Step 974 can maintain the warning, which may be accompanied by an update to the screenshots of Figures 14b and 14c.

Continuing with reference to FIG. 12 a , it will be appreciated that, in addition to the foregoing description, embodiments of data correlation step 970 may be used to perform any suitable form of monitoring related to ongoing system operations, in any suitable combination. For example, one factor distinguishing a potential fracturing leak condition from a potential cross-bore condition may be based on the rate of change of downhole mud pressure over time as detected in step 952 . In the case of a cross-bore, the downhole mud pressure may exhibit a very rapid rate of decline that can result in a sudden pressure drop. This sudden drop may be of short duration based on the push-pull rate of the drill string and the path width of the cross-bore, and may not be reasonably detected, at least from a practical perspective for the system operator. Subsequently, after crossing the cross-bore, the downhole pressure may exhibit an opposite and rapid rate of increase. In fact, a negative-going pulse may be present in the downhole pressure. Monitoring via data correlation step 970 may encompass any desired one of these pulse characteristics and/or combinations thereof. While the alert at 974 may be based on detecting an initial drop in downhole pressure, in some embodiments, the alert may be tailored based on characteristics consistent with encountering a cross-bore as detected by detecting portions of a negative downhole pressure pulse, as well as other factors yet to be described. In this case, the alert at step 974 may indicate the likelihood of a cross-bore based on how well the detected pressure changes conform to an expected or predetermined pressure profile.

In another aspect or embodiment, data correlation step 970 may monitor downhole pressure increases to levels that indicate or predict potential fracturing leaks. For example, a baseline downhole pressure may be established for each drill pipe. If the downhole pressure appears to increase above an upper limit based on the baseline downhole pressure, the warning at 974 may be customized to indicate the potential for fracturing leaks in response to high downhole pressure. In embodiments, monitoring may be based solely on the rate of increase in downhole mud annular pressure. For example, a response may be initiated in the form of an alert and/or system operation may be automatically suspended. In this regard, the rate of increase in downhole mud annular pressure may be compared to a threshold. Monitoring may be coordinated with the pumping intervals of the mud pump 32 of FIG. 1 , described in further detail below, so that a response is not initiated based on the pressure increase caused by the activation of the pumping intervals. Using the rate of increase in annular downhole pressure, a response can be predicted, allowing for the complete avoidance of excessive downhole pressures in at least some circumstances. In some cases, the rate of increase in downhole pressure (at least when it exceeds an upper limit) may form the basis for increasing the perceived urgency of the warning provided to the operator. In an embodiment, system operation may be automatically suspended in response to exceeding an upper limit to at least allow the downhole pressure to drop to a value below the upper limit. In another embodiment, system operation may be suspended in response to the rate of change of downhole pressure when approaching and/or exceeding the upper limit.

FIG15a includes a diagrammatic representation of various parameters plotted against time, with the graphs aligned vertically to illustrate specific operational conditions. Graph 1000 shows drill string length s as a function of time, while graph 1004 shows the status of whether the drill string is advancing or retracting. For illustrative purposes, it is assumed that in-ground operations are forming a pilot hole by advancing the drill string one pipe section at a time at a series of intervals, such as _t1 - _t2 , _t3 - _t4 , _t5 - _t6 , _t7 - _t8 , and an interval only partially shown and starting at _t9 , although this is not required. Because the drill string is assumed to advance at a uniform rate during each advancement interval 1006a-1006e (though this is not required), the drill string length s increases linearly during each advancement interval and remains fixed between advancement intervals, while various operations can occur, such as adding new drill pipe to the surface end of the drill string at the drill rig. The same applies to the other graphs shown, with the advancement intervals shown as being spaced at equal intervals, although this is not required. Mud pump status graph 1010 illustrates a situation where mud pump 32 ( FIG. 1 ) is operating in a series of spaced-apart pumping intervals 1012 a - 1012 e to provide uphole mud pressure. Uphole mud pressure is illustrated by graph 1020 , which shows a series of uphole mud pressure pulses 1024 a - 1024 e corresponding to the operation of the mud pump. Generally, the amplitude of these pressure pulses can be specified within a wide range of available operating values that can be selected, for example, based on soil type. For example, a relatively low pressure, such as 300 psi, detected by the uphole system can be used for sandy soils, allowing the inground tool to be configured to deliver a relatively large volume of drilling mud, for example, by using a relatively large jet on the inground tool. While 300 psi may be a relatively low pressure for a drilling system, it still represents the lower end of what is considered the overall high-pressure range. In contrast, for clay-based soils, while using a relatively small jet, the mud pressure can be set at the upper limit of the mud pump's pressure capability, such as 1300 psi. In either case, and at intermediate operating points, large volumes of drilling fluid can be delivered rapidly into the ground, making such delivery potentially problematic in terms of generating fracturing leaks when the inground tool is stationary. In some embodiments, another downhole mud pressure sensor can be employed to sense the pressure inside the drill string near its inground end. This measurement can be used, for example, to detect whether one of the drill pipe joints has become loose or disconnected.

Still referring to FIG15a, a graph 1040 schematically illustrates downhole mud pressure versus time, corresponding to uphole mud pressure 1020, wherein a series of downhole mud pressure pulses are indicated by reference numerals 1042a-1042e. Pulses 1042a, 1042b, and 1042d represent normal conditions, such as during drilling. Because drilling mud is typically thixotropic, becoming fluid when disturbed or pumped and returning to a gel state when allowed to stand still, the initiation of pumping typically results in an initial downhole pressure rise 1046 (one of which is shown) as the drilling mud begins to flow. In embodiments, this peak can be detected as a baseline pressure upper limit for the downhole mud pressure.

During normal operation, downhole mud pressure may exhibit the hydrostatic pressure 1047 typically observed between downhole mud pressure pumping intervals (several examples of which are noted). The hydrostatic pressure is based on the acceleration g due to gravity of the drilling fluid and the vertical distance h between the drilling rig and the inground tool, resulting in the following expression:

Thus, for example, in the embodiment of step 952 of FIG. 12 a , the minimum threshold value for downhole mud pressure may be based on hydrostatic pressure.

As described above, if the baseline upper pressure limit for downhole mud pressure is exceeded, the data correlation step 970 of FIG. 12a can provide a warning or notification. For example, peak pressure 1048 is illustrated using a dashed line as a different form of downhole mud pressure pulse 1042c. As described above, overpressure conditions such as those exemplified by peak pressure 1048 can lead to frac leaks, particularly when the in-ground tool is stationary. Regardless of the shape of pulse 1042c, frac leak 1050 is shown as having occurred at the end of the pulse. Generally, a frac leak or cross-bore encounter can correspond to a pressure drop below the normal operating plateau 1054, which can form part of each downhole mud pressure pulse. A frac leak can be characterized by a premature drop in plateau 1054 and a relatively slow rate of premature pressure drop. For example, pressure drop 1056 as part of pulse 1042e corresponds to a cross-bore, characterized by a rapid pressure drop and pressure change rate, as described further below.

In the embodiment of step 970 of FIG. 12a , the rate of change of downhole mud pressure, when the pressure drops below plateau 1054, for example, can be used as at least part of the distinction between a potential frac leak and a potential crossbore. Even though the transit time through a crossbore may be short, the downhole mud pressure typically drops significantly, for example, at a rate of drop of -50 psi per second. In one embodiment, a threshold value can be used to distinguish between a potential frac leak and a potential crossbore. As a non-limiting example, the threshold value can be selected within a range of -20 psi/second to -100 psi/second. In another embodiment, which can be combined with other embodiments, the operating conditions that are indicative of a crossbore include satisfying steps 950, 952, and 956 of FIG. 12a and the movement of the drill string, for example, as indicated by the size counter 28 of FIG. 1 . The result of this logic equation/expression can be monitored via step 970 of FIG. 12a . In this regard, it should be appreciated that in this example, the drill string begins advancing at _t9 in the drill string length graph 1000, however, the use of this expression is equally applicable during drill string retraction, such as during backreaming operations for installing utilities.

Another potential characteristic of a cross-bore may be a recovery segment 1060, represented as a dashed extension of the downhole mud pressure graph 1040. Initially, the downhole fluid pressure decreases to approach the pressure existing in the cross-bore, such as, for example, the pressure existing in a sewer line. Given sufficient time, the downhole fluid pressure may match the pressure existing in the cross-bore. Because drilling through and passing through a sewer line may take only seconds, the operator is unlikely to be able to stop drilling in time to prevent passage through the line. The slope of the recovery segment 1060 may be relatively steep. However, after traveling during the recovery segment 1060, at least some drilling mud may return to the cross-bore in the annular area around the drill string or utility being pulled back, which helps limit the magnitude of the pressure recovery. Therefore, the initial rise or increase in the recovery segment, as shown in FIG15 a, before encountering the cross-bore, is likely to be lower than the downhole mud pressure. The traversal interval I through the cross-hole can be short, depending on factors including the drill string advance/retract rate, the cross-hole diameter, and the angle at which the cross-hole is penetrated. Typically, a rapid recovery of downhole mud pressure will not be apparent due to the presence of a frac leak. In one embodiment, step 970 can monitor the recovery segment 1060 as part of the differentiation between a potential frac leak and a potential cross-hole condition. It will be appreciated that interval I can correspond to a data acquisition interval, as described above, allowing endpoints to be established to encompass the entire event of interest.

Referring to FIG. 12 b , attention is now directed to an embodiment of a method, generally designated by reference numeral 1300 , for detecting crossholes based on various forces that can be monitored during pilot hole formation. As described above, force sensor 529 can sense drill bit force, which can be recorded, for example, as part of force data 944 in the data structure of FIG. 13 . Force data 944 can also include thrust, which is a measure of the force exerted by the drill rig on the uphole end of the drill string as it is driven into the ground. Thrust can be measured using various methods, such as hydraulics. Each form of force data recorded can be associated with drill string length. The method begins at 1302 and proceeds to step 1306 , which retrieves the current drill string status, for example, from the most recent value of push/pull rate data 932 in FIG. At 1310 , a determination is made as to whether the drill string is advancing. If the drill string is not advancing, the operation returns to 1306 , thus continuing the monitoring process in a loop. On the other hand, if the drill string is advancing, the operation proceeds to step 1314, where the current or most recently updated values of the drill bit force and the thrust being applied by the drill rig are obtained. At step 1318, the thrust is compared to the drill bit force. This comparison can be based, for example, on a threshold difference. The latter value can be determined in any suitable manner, including empirically. It should be understood that the thrust applied to the drill string by the drill rig is always higher than the drill bit force. In the presence of helical distortion, force transmission losses can be caused by friction, borehole geometry, and applied torque. As the drill string advances with the drill bit rotating, drill bit force measurements can exhibit large fluctuations, for example, on the order of 30%, even in homogeneous soil formations. However, as soon as the drill bit enters a void, such as a crosshole, the drill bit force rapidly drops to near zero. In some cases, the drill bit force may be relatively low during drilling. For example, if the formation is sand below the groundwater level, the drill bit force may be very low. However, proper drilling practice requires the use of higher viscosity mud with low jet pressure so as not to create a large number of voids ahead of the drill tool. Therefore, cross-hole detection can still be achieved based on drill bit force. In an embodiment of step 1318, the threshold value may involve detecting a rapid drop in drill bit force over time. As a non-limiting example, if the drill bit force drops to less than 10 lbs in less than 0.1 seconds while the drill bit is moving forward in homogeneous soil, the drill bit has encountered a void, such as a cross-hole.

If the threshold difference is not exceeded, the operation returns to 1306. If the threshold difference is exceeded, the operation proceeds to 1322, where an operator warning can be issued. Of course, the initial detection of a potential cross-bore can initiate data collection intervals, logging, remote indication, and other activities discussed throughout this disclosure. In this regard, the drill bit force data may indicate an interval where drill bit force is essentially absent as the drill bit traverses the cross-bore, with a sharp increase in drill bit force at the end of the interval. Step 1322 can monitor for evidence of such a recovery in drill bit force. In an embodiment, the operation can proceed to the data correlation step 970 of method 900, as shown, for example, by a dashed line within a virtual box. Thus, the determination made by method 1300 can be correlated with, for example, the pressure being monitored using method 900, thereby enhancing the confidence in the detection of a cross-bore. As a non-limiting example, uphole mud pressure can be monitored in conjunction with the rate of advancement of the drill string. If the uphole mud pressure remains constant while the drill string is moving forward in homogeneous soil, and the drill bit force drops significantly to zero, this indicates that a cross hole or void has been encountered. In this regard, it should be recognized that a sudden increase in uphole mud pressure may create a void ahead of the drill bit, which can reduce the drill bit force.

In method 1300, after step 1322, the operation may proceed to step 1326, which determines whether an operation is ongoing and whether new data is available. If an operation is ongoing and new data is available, the operation returns to step 1310. Otherwise, the operation may proceed to 1330, where the record may be sent or any activity deemed of interest may be performed. The method may end at 1334 or be paused to be resumed as needed. It should be appreciated that method 1300 may be run independently of method 900 of FIG. 12 a, run in parallel therewith, or run in a manner that provides additional input to method 900.

FIG15b is a schematic graph showing a further magnified portion of certain graphs taken from FIG15a, beginning at time _t8 . Downhole mud pressure 1040, drill string advance/retract 1004, and drill string length 1000 are shown in temporal relationship to drill rig thrust 1340 and drill bit force 1344. At _t9 , the drill string advances, which produces a corresponding increase in drill rig thrust 1348 and drill bit force 1350. However, in response to encountering a cross-hole, a significant drop in drill bit force is seen at 1354, along with a related, but less pronounced, drop in drill rig thrust 1356. Following the cross-hole, a significant recovery in drill bit force at 1360 and an increase in drill rig thrust 1362 reflect the recovery phase 1060 of downhole mud pressure. Thus, a negative-going pulse is evident in the drill bit force. As described above, method 1300 can monitor any one, any combination, or all of these various drill bit force profiles that can indicate a cross-hole. Additionally, correlation with other factors such as downhole mud pressure may be valuable.

As described above, excessive downhole mud pressure can predict a potential frac leak. However, applicants have also recognized that excessive downhole pressure can be encountered in response to another set of circumstances. Specifically, excessive downhole mud pressure can arise in response to encountering a cross-hole subjected to high internal pressure, such as a high-pressure gas main. Pressures in such a main can reach as high as 1,500 pounds per square inch. By utilizing such high pressures, utility companies can use the gas line itself as a storage tank, which can be referred to as a line fill. When encountering a high-pressure gas line acting as a cross-hole, an extremely rapid increase in the sensed downhole mud annulus pressure can occur. For example, a spike or positive pulse 1364 in the downhole mud annulus pressure is shown as the dashed line in the graph of FIG. 15b. Applicants have recognized that spike 1364 can be distinguished from excessive downhole annulus pressure that predicts a frac leak. For example, the latter condition can arise from an annular area around the drill string clogged with drill cuttings. If the mud pump 32 of Figure 1 is limited or set to a specific maximum pressure, high-pressure cross-holes can be distinguished based on the downhole mud annulus pressure exceeding the specific maximum pressure of the mud pump. Therefore, the high-pressure cross-hole detection threshold can be based on the specific maximum pressure of the mud pump. Of course, this process can also result in the hydrostatic pressure of the drilling mud at the current depth of the drill bit or reaming tool. In some embodiments, the high-pressure cross-hole detection threshold can be a predetermined fixed value. For example, the value can be set to be higher than the maximum pressure that can be obtained from the mud pump. Such a process can be easily incorporated into the method of Figure 12a. In addition, the detection of excessive downhole mud annulus pressure itself can help detect high-pressure cross-holes. Therefore, the warning can indicate that the operator should check the cause of the high pressure, such as some problem with the flow of drilling mud or about encountering a high-pressure cross-hole.

Attention now turns to FIG. 16 , which is a further schematic, enlarged view of the in-ground distal end of the drill string 16 and drill tool 54, taken from FIG. 1 , and shown here to serve as a framework for the discussion of the integrated pitch technique. Applicants recognize that the depth of the drill tool is directly affected by its pitch orientation as it advances. In the prior art, depth determination is typically based on pitch measurements taken at locations corresponding to opposite ends of each drill pipe segment. That is, Applicants are not aware of any prior art that relies on taking pitch orientation at intermediate locations along the length of each drill pipe segment as the drill string advances. According to the integrated depth technique disclosed herein, pitch readings can be taken at multiple locations along the length of each drill pipe segment. In FIG. 16 , each point 1400 a - 1400 p represents a location and a corresponding pitch reading or value measured in response to the advancement of the drill string. For each pitch value, the system determines the corresponding drill string length as output provided by the dimension counter 28 at the drill rig. It will be appreciated that the dimension counter can determine the length of the drill string with high accuracy, for example, to within at least a quarter of an inch. For a nominal drill pipe length of 20 feet with pitch determination intervals of 2 inches, 120 pitch values can be measured. Since the bending of typical drill pipe over distances as short as 2 inches is often negligible, it can be assumed that the drill tool advances along a straight line segment Δs _i corresponding to each pitch value, where the variable i is an index value of the pitch measurement interval. For a given drill pipe length, as the number of pitch measurements i increases, the depth determination accuracy can increase accordingly and approach the integral value of the depth. The embedded view 1420 shown within the dashed circle of Figure 16 shows an x-axis that corresponds roughly to the horizontal advance direction along the drilling direction and a z-axis that is positive in the vertical downward direction and represents the depth d. Therefore, for a given pitch determination increment corresponding to the advance increment Δs _i in the drill string, the depth change Δd _i is given by the following expression:

Of course, the total depth at any given time is equal to the current depth plus the incremental depth change, which can be positive or negative. Thus, the current depth of the drill string can be determined with high accuracy. The incremental increase can be based solely on measurements taken by a device monitoring the movement of the drill string (e.g., counter 28 of FIG. 1 ) or on a certain number of measurements taken on a per-drill rod basis. At a minimum, incremental movement can correspond to half the drill string length so that at least one intermediate pitch measurement can be taken at the midpoint of the drill string. As a non-limiting example, the measurement interval can be within the range from half the drill string down to the measurement resolution of counter 28. Suitable and convenient intervals include one foot, two inches (as described above), six inches, one meter, and 10 centimeters. However, it should be appreciated that increasing the number of measurements per drill string (i.e., reducing the incremental movement per measurement) can improve the accuracy of the overall depth determination. While the integrated depth technique discussed represents the movement of the inground tool as if it were moving in a series of incremental movements, it should be appreciated that, in reality, the operator does not need to physically move the drill string, and thus the inground tool, in accordance with the incremental movements. The movement and the associated measured values can be determined or characterized automatically in the background and in a manner invisible to the operator.

Based on the above, the system can be optimized with respect to measurement intervals in a manner intended to increase the number of pitch readings that can be transmitted from the drill tool to the drill rig via the drill string, and based on the measurement capabilities of size counter 28. This provides significant flexibility. In one embodiment, the number of incremental pitch readings can be based, for example, on the throughput capacity (i.e., bandwidth) of the drill string communication system established between the drill tool and the drill rig. Practical embodiments can utilize intervals ranging from sub-Hertz to kilohertz. In this regard, it is not necessary to utilize regular pitch measurement intervals, as can be seen in FIG16 . The pitch measurement interval can vary, for example, based on the current data traffic of the drill string communication system. In some embodiments, the frequency of incremental pitch measurements (i.e., between adjacent points 1400a-p in FIG16 ) can be based on the current pitch value. For example, if the pitch reading approaches horizontal, the frequency of pitch measurements can be reduced, while the frequency can be increased proportionally to the deviation from horizontal. In another embodiment, the rate of change of the pitch reading can be monitored, such that the frequency of pitch measurements can be increased proportionally to the increasing rate of change of the drill tool pitch. Additionally, incremental pitch readings and related data may be automatically collected. In some embodiments, the drill rig may automatically be temporarily paused when each incremental pitch reading is collected for the purpose of mitigating noise in the sensor data.

Referring to FIG. 17 in conjunction with FIG. 16 , FIG. 17 is a flow chart generally designated 1200 and illustrating an embodiment of a method for determining integrated depth according to the present invention. The method begins at a start step at 1204 and proceeds to step 1208 , which may receive as inputs the current change in drill string length Δs _i for the first pitch reading and the current depth value d. At 1212 , the incremental depth change Δd _i for the current increment i may be determined based on equation (1). At 1216 , a determination is made as to whether another incremental pitch value is available. If a positive determination is made, operation proceeds to step 1218 , which receives the relevant inputs and then loops the process back to step 1212 to determine a new incremental depth change and an updated current total depth. Once step 1216 determines that all incremental pitch readings have been processed, operation proceeds to step 1220 to output the integrated depth value, and the method may end at 1224 .

In another embodiment, the incremental pitch readings of FIG. 16 can be measured during a pullback after drilling each length of drill string. In this way, incremental pitch readings can be obtained without being affected by the noise and vibration levels present during advancement of the drill string (which is often referred to as piloting). It will be appreciated that the pullback and incremental pitch reading processing can be automated. At least because each incremental pitch measurement is associated with a unique length of drill string, method 1200 can determine the integrated depth regardless of the specific order in which the pitch readings are obtained. In some embodiments, the pitch readings from the piloting operation can be combined with the pitch readings obtained during the pullback.

In another embodiment, when the inground tool includes a yaw sensor, such as magnetometer 522 of FIG. 10 , the integrated lateral motion of the inground tool can be determined. That is, the motion of the inground tool can be determined relative to the y-axis, which is perpendicular to the x-z plane shown in FIG. 16 . The measured positions 1400 a-1400 p would then represent yaw sensor readings along the length of the drill pipe. It is believed that one of ordinary skill in the art, given the entire disclosure of the present invention, would be readily able to implement this embodiment.

Attention now turns to FIG. 18 , which schematically illustrates a pullback or backreaming operation performed in area 1600, for example, using inground tool 20 of FIG. 9 and drill rig 14 of FIG. Portable device 80 ( FIG. 1 ) and associated communication paths may be utilized, but for clarity, they are not shown in FIG. 18 . The backreaming operation is shown as partially pulling utility 1604 (shown as a thick, solid line) through a previously formed pilot hole 1608 (shown as a dashed line). Pilot hole 1608 passes beneath a body of water 1612 and leads to drill rig 14. However, during the illustrated backreaming operation, a condition known as "keying" occurs along the pilot hole between points P1 and P2, causing the drill string, and therefore the utility, to deviate from the original path of the pilot hole. Between point P1 and inground tool 20, the displaced or keyed drill string is indicated by reference numeral 1614 and shown as a solid line. As a result, the utility will be located above the existing pilot hole between P1 and P2. As shown, this drill string wedging phenomenon can problematically cause the drill string, inground tool 20, and/or utility 1604 along portion 1614 to inadvertently contact cross-hole 1620 or other inground obstructions. Of course, additional wedging occurring at any given location along the pilot hole behind the inground tool cannot be detected because sensing is performed at the inground tool; however, if wedging is not detected at the inground tool during the ongoing pullback operation, such additional wedging is unlikely to occur. Furthermore, the upward force applied to the soil by the utility during the pullback is typically less than the force applied by the drill string, particularly when the operator employs known measures such as filling the utility with water to counteract its buoyancy. These upward forces are described in detail below.

Still referring to FIG. 18 , attention will now be directed to an analysis of the factors that contribute to the wedge hole. The drill rig 14 applies a tensile force T, indicated by the arrow, to the drill string 16 located in the pilot hole between the inground tool 20 and the drill rig. In response to force T, a force T _1, indicated by the arrow, is applied to the utility 1604 when the utility 1604 reaches point P ₃ , and a force T _0, indicated by the arrow, is applied to the utility at the point where the utility enters the ground. Although not shown, the entry point may be, for example, located in the depression to which the pilot hole originally extended. The coefficient of friction to which the utility is subjected when it contacts the soil is μ. For a typical drilling mud, which may be characterized as, for example, a 60-second mud (e.g., as measured using a Marsh funnel viscometer), the coefficient of friction may be approximately 0.2 to 0.4. Where the differential path length ds is the product of the local radius and the corresponding differential arc length dθ, the relationship between T ₀ and T ₁ may be expressed as:

where _θ2 is an angle based on at least the approximate radius of the guide hole from _P3 to _P4 . The upward force between points _P3 and _P4 due to tension can be expressed as:

where _θ1 is an angle based on at least the approximate radius of the pilot hole from _P5 to _P6 . When assuming the utility being installed is neutrally buoyant, the upward force between points _P5 and _P6 due to tension can be expressed as:

Wherein, _T2 indicated by the arrow is the tension at point _P5 .

Based on the upward forces given by equations (4) and (5), if the upward forces at a given location are distributed over the area defined by the drill string or utility that is applying the force, then a wedge hole may occur anywhere the force applied per unit area is greater than the compressive strength per unit area of the local soil formation.

In one embodiment, drill string keyhole can be detected based on comparing pilot hole pitch values acquired along the borehole path while drilling a pilot hole with pullback pitch values acquired while pulling back inground tool 20 along the pilot hole during a backreaming operation. In this regard, a system according to the present invention can rapidly generate orientation and other hole path-related data, such as pitch sensor values 1400a-1400p shown in FIG16 . It should be appreciated that pitch readings can be acquired by inground tool 20 at a comparable frequency during a backreaming operation. As shown in FIG18 , between points _P1 and _P2 , the pitch values acquired along the pilot hole and those acquired during the backreaming operation do not match due to the occurrence of drill string keyhole. Therefore, for any given length of drill string 16 obtained from size counter 28 ( FIG1 ) during a pullback operation, the current pitch value at the inground tool during the pullback can be compared with the corresponding pilot hole pitch value. A threshold pitch change can be specified for this comparison, with a warning issued whenever the difference from this comparison exceeds the threshold. In one embodiment, the threshold pitch change can be 1 degree or less. From a practical perspective, the frequency with which inground tool 20 obtains pitch sensor values during a pullback can provide real-time monitoring, at least because the pitch readings during pilot hole formation and pullback can differ by fractions of an inch. In one embodiment, as each pullback pitch value is obtained, a comparison can be made substantially in real time.

In another embodiment, which may be used independently of or in conjunction with the above-described embodiments, for example, as described above with reference to FIG. 16 , an integration method may be used to track the depth of inground tool 20 during pullback. To detect drill string keyholes, the depth of the current drill string length during pullback may be compared to the recorded depth value of the pilot hole at the current drill string length. Furthermore, the difference between the recorded pilot hole depth and the current pullback depth may form the basis for an alert when a specified depth delta threshold is met and/or exceeded. In one embodiment, this threshold may be 2 feet or less. In some embodiments, depth values measured along the hole path using a portable locator (which may be referred to as "confidence points") may form part of this comparison. Confidence point measurements may be acquired at various points during the pilot hole formation and during the pullback. In one embodiment, the system may prompt the operator during the pullback to acquire a pullback confidence point measurement that corresponds to the pilot hole confidence point measurement for direct comparison. In this regard, automatic pitch- or depth-based monitoring may be performed for drill string keyhole detection during the pullback operation.

In another embodiment, an advanced system capable of determining the actual position and/or orientation of the inground tool may be used, such as described in U.S. Patent No. 7,425,829 and U.S. Patent No. 8,831,836, both of which are incorporated herein by reference in their entireties. In other embodiments, the inground tool may include an inertial navigation system (INS) capable of determining the position and/or orientation of the inground tool. In such embodiments, the recorded depth of the drill tool along the pilot hole may be compared to the depth of the inground tool 20 during the pullback operation, in a manner consistent with the above description of performing a pitch comparison. Referring to FIG. 19 , an embodiment of a method for detecting drill string keyholes is generally indicated by the reference numeral 1700. The method begins at 1704 and proceeds to step 1708, which retrieves the pilot hole data of interest, for example, from data structure 920 of FIG. At 1712, current parameter values may be received during the pullback operation and may also be recorded as part of pullback data 942 in the data structure of FIG. 13 . The current parameter can be selected as any one of pitch, depth, and position. In some embodiments, comparisons can be made with respect to more than one parameter. At 1716, the drill string length can be determined for the current parameter. At 1720, the current parameter is matched to the corresponding pilot bore parameter. If the recorded pilot bore parameter corresponds to a drill string length that falls on either side of the current drill string length, an extrapolated value can be readily determined for comparison purposes. At 1722, a determination is made as to whether the current parameter is within an acceptable range based on the corresponding pilot bore parameter value. This determination can be based on thresholds established for each parameter to which the method is applied. As non-limiting examples, the pitch threshold can be one degree or a smaller fixed value, the depth threshold can be between 6" and 12", and the position threshold can be between 6" and 12". If the comparison at 1722 indicates that the current parameter is within limits, the operation can return to step 1712 to receive updated current parameter values as the pullback operation continues. As described above, the comparative analysis is not limited to a single parameter; more than one type of parameter can be used simultaneously in method 1700. Furthermore, the parameters used for comparison can be generated during the via hole formation process in a different manner than the parameters generated during the pullback process. As a non-limiting example, depth can be determined during via hole formation based on measurements of positioning signals (e.g., electromagnetic readings), while depth during the pullback process can be characterized using pitch measurements based on the integrated depth technique described herein.

Continuing with FIG. 19 , if the current parameter exceeds the relevant threshold in step 1722, the operation may proceed to step 1730, which may notify or warn the operator that a drill string keyhole may occur at the current location of the inground tool. A drill string keyhole warning may be handled in a manner consistent with the other types of warnings described above. For example, a log may be recorded locally and/or remotely, and a warning recorded locally and/or sent to a remote location. In one embodiment, data representing the drill string length may be graphically presented to the operator and/or to a remote location to illustrate potential drill string keyholes. Operations may be manually or automatically paused to await a determination by the operator or other authority appropriate to resume operations. After step 1730, the method may terminate at 1732, but may be restarted as needed. It should be appreciated that data transmission for detecting drill string keyholes may be accomplished using any suitable communication path and/or method.

Referring again to FIG. 18 , applicants have recognized that pullback data can often include a more accurate representation of the actual installed location of a utility than pilot hole data. Thus, data representing the utility in its as-built form can be generated from the pullback data 942 of FIG. 13 . In this regard, the prior art typically characterizes installed utilities based on pilot hole data, a characterization that can be significantly inaccurate when factors such as drill string keying come into play. Referring to FIG. 1 , during the formation of a pilot hole using system 10, there may be times when an operator elects to perform repetitive motion of the drill string as the drill string is selectively actuated with coordinated advancement and retraction of the drill string. This activity, which may be referred to as auto-grooving, may be employed, for example, when attempting to achieve a specific pitch orientation of the drill bit to manually or automatically adhere to a predetermined hole plan.

Referring to FIG. 20 , which is generally designated by reference numeral 1800, FIG. 20 illustrates the rotation of a drill bit or tool head about an elongated axis 1804 defined by the drill bit, which may be referred to as path carving. This process may be used when the compressive strength of the soil is so high that the drill rig cannot push the drill bit through the soil to achieve guidance without rotating the drill string. In other words, the drill bit cannot be advanced by simply pushing the drill bit. The purpose of path carving is to mechanically manipulate the borehole to provide an offset orientation for the drill bit to achieve guidance. Typically, as a non-limiting example, path carving involves rotating the drill bit through a limited rotational range, such as a groove spacing 1810 from position A to position B (a range of 120 degrees), although any suitable groove spacing angle may be used. When rotated, for example, in a clockwise direction, the drill bit advances an incremental distance approximately less than or equal to the length of the drill pipe section. In some embodiments, this distance may be only on the order of a few inches. The drill bit is then rotated in the same rotational direction from the roll end position B of the groove interval back to the roll start position A of the groove interval, which may be referred to as the indexing interval 1814. In conjunction with the indexing interval, the drill string may be retracted, for example, by 3 to 6 inches, before rotating to the roll start position of the groove interval. This is sufficient to allow the drill bit to separate from the undrilled surface of the hole. This process is then repeated, for example, manually by an operator, until terminated. Because automated groove cutting is often performed in hard soil and rock, drill pipe winding can occur: that is, unpredictable rotation of the drill bit in response to the rotation of the drill string driven by the drill rig. When winding occurs, the drill bit may completely release and "snap" past the target roll position, such as the start position of the groove interval, or past the entire groove interval. Consequently, to achieve the target roll position, the drill string must be continuously rolled until the target roll position is achieved. Clearly, path cutting can be complex, lacking accuracy, and not providing a fast update indication of the drill bit's roll position.

Attention is now directed to the flowchart of FIG. 21 , which illustrates an embodiment of an automated grooving or "autogrooving" technique, generally designated by reference numeral 2000. The method begins at a start step at 2004 and proceeds to step 2008 , which typically begins with the drill bit at rest by reading various values, such as current values for roll orientation, pitch orientation, yaw orientation, drill string length, and drill bit force, from data structure 920 of FIG. 13 . The latter may be non-zero at the start of the process. If so, it will be appreciated that the drill bit may be free to roll in a manner consistent with the description below. At 2012 , the method obtains input parameters for defining the targets of the autogrooving process. These values may be specified, for example, by an operator using console 42 ( FIG. 1 ) at the drill rig, although the parameters may be specified from any suitable location. Using FIG. 20 , as a non-limiting example, the various inputs may include an autogrooving range from position A to position B, a target pitch orientation T and/or a target yaw orientation, and the number of autogrooving iterations to be performed. In some embodiments, default values may be used for A and B, the number of iterations, and/or other parameters. Other parameters may include, for example, thrust and rotational speed. At 2016, in this example, the drill bit is rotated clockwise to position A. As is conventional, rotation is performed only in the direction in which the line joint is tightened into the drill string. At 2020, while thrust is applied to the drill string, a groove interval operation is performed from rolling orientation position A to rolling orientation position B. Of course, during the groove interval, drilling mud can be injected as a jet 52 (Figure 1), but this is not required. After the groove interval, at 2024, the drill string is retracted, and the retraction amount is sufficient to relieve the pressure acting on the borehole face (for example, indicated by the drill bit force sensor 529). As the applicant recognizes, for reasons yet to be described, this retraction amount can be limited to an amount that is just sufficient to provide free rotation or non-contact rotation of the drill bit in the borehole.

At 2028, the drill bit force is sensed to determine whether the pressure acting on the borehole face has been relieved. This pressure is typically associated with the ability to rotate the drill bit freely without contact with the borehole face, or, at least from a practical perspective, drilling as if no contact is present, even if incidental contact does not affect the process results. If the drill bit force cannot be relieved, step 2024 is repeated until test 2028 is satisfied. Next, at 2032, a shift interval operation is performed from roll position B back to roll position A. Rolling can continue automatically, for example, if drill pipe spooling causes the system to miss position A at any given rotation. At 2036, the current data values are again read from the sensors described with reference to step 2008. It should be noted that, for example, the appropriate data for step 2036 corresponds to any data read outside of the groove interval 1810 when the drill bit is stationary, rotating in a contactless manner (i.e., free-spinning), and/or retracting. This ensures that data accuracy is not degraded by vibrations and unpredictable accelerations that may be present during the groove interval. At 2040, the current parameters and data can be compared to the target values of step 2012. If it is determined that the target parameters have been achieved, the operation can proceed to step 2044, which can indicate that the process is complete based on the specified target, and the process can end at 2048. On the other hand, if step 2040 determines that the target has not been achieved, the operation can proceed to step 2052, which can perform an analysis of the process parameters based on, for example, a comparison of the target values with accumulated data from one or more iterations, including at least the current iteration. At 2056, if the analysis determines that the accumulated iteration data and the current iteration data are approaching the target and that another iteration can be used for each target number of iterations, the operation can return to 2016. If the analysis determines that the data for the current iteration is beginning to deviate from the target values, the operation can proceed to step 2044, which provides notification that the notching process should be terminated based on at least the currently specified target parameters. In some cases, the analysis can rely, at least to some extent, on the accumulated iteration data as well as the current iteration data. In one embodiment, step 2052 may determine that soil conditions permit travel in a specific direction other than the target direction or deflection angle. In this case, the operation may proceed to step 2044, where a notification may inform the operator of available or alternative travel directions and, in one embodiment, provide a revised target T and/or endpoints A and B for approval and/or modification during a new set of iterations. The operation may then resume at step 2056.

The analysis at step 2052 is premised on obtaining sensor and parameter inputs from step 2036 that accurately represent the progress being made during the autogrooving iterations. It will be appreciated that excessive retraction of the drill string between groove intervals can have at least two detrimental consequences. The first detrimental consequence is obtaining sensor and parameter values that do not adequately represent progress or that lack sensor and parameter values associated with the specified autogrooving target. Consequently, the process may be prematurely terminated, even though it is on track to produce the target result. Relatedly, there is a risk of continuing iterations when sensor data should indicate that the process is gradually deviating from the target value during the iterations. The second detrimental consequence is that actual progress toward the target value is completely erased due to excessive retraction. For example, if a positive increase in pitch is desired, the effects of gravity and excessive retraction can easily negate the previously achieved positive increase in pitch. However, these deleterious consequences can be greatly limited or eliminated entirely by using the drill bit force data to limit the retraction of the drill bit at least approximately to a distance just sufficient to relieve the drill bit pressure acting on the borehole face, steps 2024, 2028. In this way, the amount of change in the drill bit's orientation in response to retraction can be limited in a manner that continues to provide accurate sensor readings.

Referring to FIG. 16 in conjunction with FIG. 1 , system 10 eliminates the limitation of requiring rapid roll orientation updates because a roll orientation update can be provided whenever a pitch orientation update is performed for positions 1400 a-1400 p in FIG. 16 . The pitch orientation update can be provided corresponding to less than one inch of movement of the inground tool. With respect to a fixed rotation of the drill bit, a roll orientation update can be provided, for example, at least every 0.1 seconds, corresponding to a known amount of drill bit rotation based on the rotational speed employed by the drill operator or programmed for automation purposes. In an embodiment, automatic notching can request additional allocation of drill string communication bandwidth for roll orientation updates. In this regard, this allocation can be coordinated with monitoring of the drill bit's stationary state (i.e., lack of lateral movement) so that even bandwidth typically allocated to pitch orientation updates can be reallocated to roll orientation updates at these times.

The disclosed techniques represent various combinations of data derived or generated from uphole and downhole data sources. When properly analyzed, these various combinations of data can result in indications, based on which appropriate responses can be initiated according to the teachings herein. In some embodiments, the combined data can improve the ability to track the position of an inground tool. For example, the disclosed integrated depth technique utilizes pitch information from a downhole pitch sensor and drill string length from a sizing counter at the drilling rig to more accurately characterize the depth of the drill string. The disclosed integrated lateral motion technique utilizes deflection information from a downhole deflection sensor and drill string length from a sizing counter at the drilling rig to more accurately characterize the lateral position of the inground tool. In other embodiments, the combined data can improve monitoring and management of the detection of adverse operating conditions. For example, embodiments of fracture leakout and cross-hole detection techniques can utilize uphole determined parameters, such as uphole mud pressure, sizing counter data representing drill string length and motion, and mud flow data, as well as downhole data, such as downhole mud annular pressure, to generate indications, in response to which the system and/or operator can take additional actions. In another embodiment, either independently of or in combination with the aforementioned embodiments, cross-hole detection can be based on uphole data, including drill string thrust status and rig thrust, and downhole data, including, for example, drill bit force, to detect whether a potential cross-hole has been encountered, thereby forming the basis for a subsequent response. In another embodiment, drill string keyhole detection can be based on correlating downhole information with formation data from both pilot holes and pullbacks, as indicated by drill string lengths generated using an uphole sizing counter. Thus, by monitoring and analyzing various combinations of rig-derived and downhole data in heretofore unknown ways, the described technology can provide methods for improving tracking accuracy and reducing traditional risks associated with the installation of buried utilities.

Having initially referred to FIG. 1 in the context of the present system, attention will now be directed to a discussion of data communications. It will be appreciated that telemetry communications between a portable device 80 (which may be a lightweight locator) and a drilling rig may be subject to reception limitations. For example, the telemetry signal may be too weak to ensure sufficient reliability in data communication. Unreliable telemetry may be caused by range limitations, terrain, intervening structures such as buildings, local interference/noise, power line harmonics, and low signal strength, among other limitations.

Referring to FIG. 22 in conjunction with FIG. 1 , FIG. 22 illustrates an embodiment of a method, generally designated 2200, for telemetry monitoring. The method begins at 2204 and proceeds to step 2208, which monitors the quality of the telemetry signal 92. This monitoring can be performed, for example, by the drill rig processor 70 at the control console 42, or by some other available component at or near the drill rig. Signal quality can be readily characterized by the signal-to-noise ratio (SNR). Some embodiments may obtain the signal's bit error rate (BER) or characterize the number of packets being lost or corrupted. Any suitable technique may be used to characterize signal quality, and the process is not limited to those explicitly described. Of course, more than one signal quality characterization may be used at any given time. At 2212, a determination is made as to whether the quality of the telemetry signal 92 has degraded too much to be used for continued communication. This test may be performed, for example, based on the signal-to-noise ratio, packet loss rate, etc., falling below an SNR threshold and/or a BER-related threshold. If telemetry signal 92 is determined to be lost or too weak for the drill rig to reliably receive information from it, the drill rig processor 70 can generate a prompt to be communicated to the portable device, instructing the portable device to thereafter transmit at least periodic depth readings to the inground tool via inground communication signal 99. It should be noted that if two-way telemetry is implemented and used between the portable device and the drill rig, the prompt can be sent to the portable device via the inground communication link and/or via telemetry. Thus, a set of redundant communication paths can be used to transmit the prompt. Arbitration can be performed between these paths. For example, if telemetry communication from the drill rig to the portable device is determined to be unavailable, the prompt can be transmitted over the inground communication link. Regardless of the path or paths through which the prompt is received, at 2220, the processor on the inground tool can send a message to the portable device instructing the portable device to thereafter transmit depth measurements back to the inground tool via communication signal 99. Of course, other measurements and parameters can also be switched to this path in the same manner. At 2224, system operation is resumed so that at least the depth reading is communicated by the signal 99 and sent up the drill string, with the inground tool acting as a repeater. If the test at 2212 determines that the telemetry signal 92 is acceptable, system operation can be resumed at 2228, but the process can also periodically cycle back through the telemetry monitoring steps 2208, 2212.

FIG23 illustrates another embodiment of a method for telemetry monitoring, generally designated 2300. Method 2300 can be performed in conjunction with or independently of method 2200 described above in FIG22 . In this embodiment, portable device 80 can monitor whether telemetry signal 92 transmitted from the portable device back to the control console 42 of the drill rig is lost or too weak to reliably transmit information. It should be noted that this form of monitoring can utilize the two-way telemetry of system 10, but this is not required. The method begins at 2304 and proceeds to step 2308, where, for example, the control console 42 can send a confirmation to the portable device via the drill rig's telemetry signal 96 to confirm that the telemetry signal 92 is being received. In another embodiment, this confirmation can be sent from the drill rig to the inground tool using an inground communication link (i.e., based on the locate signal 66, transmitted via the drill string, and then to the portable device). For example, the confirmation may be sent after a predetermined number of data packets have been received, or after a set or predetermined time interval. The console 42 may periodically send a confirmation back to the portable device to indicate that the information has been received via the telemetry signal 92. At 2312, if the positioning system does not receive such a confirmation or handshake on an expected basis, such as by missing at least one confirmation, the portable device determines that the telemetry signal is lost or too weak to reliably receive the information. In this case, at 2320, the portable device is configured to send at least the depth measurement to the inground tool via the communication signal 99 for forwarding by the inground tool during system operation at 2324 and up the drill string to the console or drill rig processor via the inground communication link. If the determination at 2312 determines that the confirmation has been received in a timely manner, system operation may continue at 2330 using telemetry and periodically looping back through the telemetry confirmation step.

In other embodiments, a given signal may be sent redundantly both via telemetry and by using an inground communication link. If both transmissions are successful, then the optimal route can be determined at any given time, for example based on available bandwidth or manual designation. In addition, arbitration of data may be mixed so that the system is not an all-or-nothing communication link. For example, if both transmissions are successful, the system design may be configured to send certain types of data via air and other data via pipeline for the purpose of optimizing the communication links of each system and achieving optimal performance of the overall solution. In one system embodiment, surface telemetry communication via telemetry signal 92 is not required. Thus, the subject system embodiment does not require telemetry signal 96 from the drill rig. In some system embodiments, all data communications between the drill rig and other surface components may be carried out using an inground communication link or loop, thereby allowing the inground tool to serve as an intermediate repeater for data originating from surface components such as locator 80.

The foregoing description of the present invention is provided for purposes of illustration and description. It is not intended to be exhaustive or to limit the invention to the precise form(s) disclosed. Other embodiments, modifications, and variations are possible in light of the above teachings, wherein those skilled in the art will recognize some modifications, permutations, additions, and sub-combinations thereof.

All elements, parts and steps described herein are preferably included. It should be understood that any of these elements, parts and steps may be replaced by other elements, parts and steps or completely deleted, as will be apparent to those skilled in the art.

Disclosed herein are at least the following: Systems, apparatus, and methods for initiating a response to the detection of an adverse operating condition involving a system including a drilling rig and an in-ground tool are described. The response can be based on both uphole and downhole sensed parameters. The adverse operating conditions include cross-hole detection, fracturing leak detection, excessive downhole pressure, nozzle blockage indication, and drill string keyhole detection. A communication system includes an in-ground communication link that allows two-way communication between a portable detector and the drilling rig via the in-ground tool. Depth and/or lateral movement of the in-ground tool can be monitored using techniques that approximate integral values. Drill bit force based on automated notching is described in the context of an automated procedure. Loss of locator-to-drill rig telemetry can trigger an automatic switch to a different communication path within the system.

Conception

This document also discloses at least the following concepts.

Concept 1. A method for use in conjunction with a horizontal directional drilling system, the horizontal directional drilling system comprising a drill string extending from a drill rig to an inground tool such that extension and retraction of the drill string during inground operations collectively produce corresponding movement of the inground tool, the drill string defining a passageway for carrying a pressurized flow of drilling mud from the drill rig to the inground tool for discharge of the drilling mud from the inground tool, the method comprising:

During inground operations, monitoring mud annulus pressure in the ground surrounding the inground tool;

detecting a change in the mud annulus pressure; and

A response is initiated based at least in part on detecting the change as an indication of one of a potential cross-bore and a potential fracture leak.

Concept 2. The method of Concept 1, wherein the detecting step detects a drop in the mud annulus pressure.

Concept 3. The method of Concept 1 or 2, wherein the responding step includes issuing a warning to indicate one of a potential cross-hole and a potential fracture leak.

Concept 4. The method of Concept 3, wherein the warning is issued to indicate a potential cross-bore, and the issuing step requires detecting the drop in conjunction with detecting uphole mud pressure based on an uphole mud pressure threshold, detecting mud flow based on a flow threshold, and detecting movement of the drill string.

Concept 5. The method according to Concept 2, 3 or 4, further comprising:

After detecting the drop, the mud annulus pressure continues to be monitored for recovery of the mud annulus pressure, thereby defining a negative going pulse in the mud annulus pressure and issuing the warning in response to identification of the negative going pulse.

Concept 6. The method according to Concept 2, 3, 4 or 5, further comprising:

Supplemental data is collected in response to detecting the dip, within a time interval beginning before and/or after detecting the dip.

Concept 7. The method of Concept 6, wherein the supplemental data includes uphole mud pressure, downhole mud pressure, and mud flow rate.

Concept 8. The method according to Concept 5, 6 or 7, further comprising:

Additional data including at least one of a length of the drill string and a drill string push/pull rate is collected within a selectable time interval based on a first time point at which the decline is detected and a second time point at which the recovery is detected.

Concept 9. The method according to Concept 8, further comprising:

The selectable time intervals are defined based on an offset such that the first time point is before a decrease in mud annulus pressure and the second time point is after a recovery in the downhole mud pressure.

Concept 10. The method according to Concept 2, 3 or 4, further comprising:

After detecting the drop, continuing to monitor the mud annulus pressure for recovery of the mud annulus pressure; and

In response to detecting the recovery, the response is initiated as an indication of a potential cross-bore, and when the recovery is not detected, the response is initiated as an indication of a potential fracture leak.

Concept 11. The method according to Concept 2-10, further comprising:

measuring a rate of change of a decrease in the mud annulus pressure; and

A distinction is made between the potential interspersed holes and the potential fracture leak-off based on the rate of change for initiating the response.

Concept 12. The method of Concept 11, comprising selecting a threshold value for the rate of change of the drop in mud annulus pressure within a range from -20 psi/sec to -100 psi/sec, and wherein the distinguishing step compares the measured rate of change to the selected threshold value.

Concept 13. The method according to Concepts 1-12, further comprising:

In response, operation of the drilling rig is automatically suspended.

Concept 14. The method according to Concept 1-13, further comprising:

A minimum threshold value of the mud annulus pressure is established during normal operation of the drilling rig based on hydrostatic pressure, and initiation of the response is based on the minimum threshold value.

Concept 15. The method of Concepts 1-14, wherein:

The step of initiating the response further requires detecting the change at least in conjunction with detecting movement of the drill string.

Concept 16. The method according to Concept 1-15, further comprising:

During inground operations, a gas sensor is monitored for sensing one or more gases, including natural gas, propane, hydrocarbon gases, and sewer gas, in an annular region surrounding the inground tool.

Concept 17. The method according to Concept 1-16, further comprising:

During inground operations, a gas sensor is monitored for sensing one or more gases near the drilling rig, including natural gas, propane, hydrocarbon gases, and sewer gas.

Concept 18. An apparatus for use in conjunction with a horizontal directional drilling system, the horizontal directional drilling system comprising a drill string extending from a drilling rig to an inground tool such that extension and retraction of the drill string during inground operations collectively produce corresponding movement of the drill tool through the subsurface, the drill string defining a passageway for carrying a pressurized flow of drilling mud from the drilling rig to the inground tool for discharge of the drilling mud from the inground tool, the apparatus comprising:

a monitoring device configured to monitor mud annulus pressure in the ground surrounding the inground tool during inground operations;

a sensor for detecting a change in the mud annulus pressure; and

A processor is configured to initiate a response based at least in part on detecting the change as an indication of one of a potential cross-bore and a potential fracture leak.

Concept 19. A method for use in conjunction with a horizontal directional drilling system, the horizontal directional drilling system comprising a drill string extending from a drill rig to an inground tool such that extension and retraction of the drill string during inground operations moves the inground tool through the subsurface, the drill string defining a passageway for carrying a pressurized flow of drilling mud from the drill rig to the inground tool for discharge of the drilling mud from the inground tool, the method comprising:

During drilling operations, monitoring mud annulus pressure in the pilot hole surrounding the inground tool;

detecting an increase in the mud annulus pressure exceeding an upper downhole pressure limit; and

A response is initiated based at least in part on detecting the increase.

Concept 20. The method of Concept 19, wherein said initiating step issues a warning to indicate a prediction of a potential fracture leak.

Concept 21. The method according to Concepts 19-20, further comprising:

An initial downhole pressure rise is detected in response to initiating pumping of drilling fluid, and a peak value of the initial downhole pressure rise is selected as the upper limit downhole pressure.

Concept 22. The method according to Concepts 19-21, further comprising:

When the upper limit downhole pressure is exceeded, determining the rate of change of the mud annulus pressure; and

The response is initiated as a warning to an operator, the response comprising increasing the warning urgency level in response to an increase in the value of the rate of change.

Concept 23. The method according to Concepts 19-22, further comprising:

When the upper downhole pressure limit is approached and/or exceeded, operation of the system is suspended in response to the rate of change of the mud annulus pressure.

Concept 24. The method of Concepts 19-23, wherein the drill string is comprised of a plurality of drill rods, and the step of monitoring the mud annulus pressure comprises forming a baseline downhole pressure on a per-drill rod basis and establishing the upper limit downhole pressure based on the baseline downhole pressure.

Concept 25. An apparatus for use in conjunction with a horizontal directional drilling system, the horizontal directional drilling system comprising a drill string extending from a drill rig to an inground tool such that extension and retraction of the drill string during inground operations moves the inground tool through the subsurface, the drill string defining a passageway for carrying a pressurized flow of drilling mud from the drill rig to the inground tool for discharge of the drilling mud from the inground tool, the apparatus comprising:

a monitoring device for monitoring the mud annulus pressure around the inground tool during inground operation;

a sensor for detecting an increase in the mud annulus pressure exceeding an upper downhole pressure limit; and

A processor is configured to initiate a response based at least in part on detecting the increase.

Concept 26. A method for use in conjunction with a horizontal directional drilling system, the horizontal directional drilling system comprising a drill string having a length extending from a drill rig to a drill tool having a drill bit, wherein extension of the drill string advances the drill tool through the subsurface during a drilling operation to form a pilot hole, the method comprising:

monitoring a drill bit force exerted by the drill bit on a pilot hole face during advancement of the drill tool;

detecting a drop in the drill bit force; and

A response is initiated based at least in part on detecting the dip as an indication of a potential intersection hole.

Concept 27. The method of Concept 26, wherein initiating said response comprises at least one of issuing a warning indicative of said potential cross-bore and automatically halting operation of said drilling rig.

Concept 28. The method according to Concepts 26-27, further comprising:

During advancement of the drilling tool, the drill bit force associated with the length of the drill string is recorded.

Concept 29. The method according to Concepts 26-28, further comprising:

monitoring the thrust applied by the drilling rig to the drill string to produce the advancement; and

The thrust force associated with the length of the drill string is recorded.

Concept 30. The method according to Concepts 26-29, further comprising:

In response to detecting a drop in the drill bit force and before initiating the response, confirming that the drill bit force is less than the thrust force by at least a threshold difference.

Concept 31. The method according to Concepts 26-30, further comprising:

In response to detecting the drop in drill bit force and before initiating the response, confirming that the drill bit force has dropped to less than 10 pounds in less than 0.1 seconds.

Concept 32. The method according to Concepts 26-31, further comprising:

In response to detecting the drop in the drill bit force, the drill bit force is continued to be monitored to detect a recovery of the drill bit force to confirm that there is substantially no gap in drill bit force.

Concept 33. The method according to Concepts 26-32, further comprising:

In response to detecting a drop in the drill bit force, a data collection interval is initiated to test for a recovery of the drill bit force, the recovery of the drill bit force evidenced by a negative going pulse in the drill bit force consistent with encountering a cross hole.

Concept 34. The method of Concepts 26-33, wherein the drill string defines a passageway for carrying a pressurized flow of drilling mud from the drill rig to the drill tool at least during advancement of the drill tool to discharge the drilling mud from the drill tool, the method further comprising:

relating the drill bit force to uphole mud pressure as the drilling mud is pumped into the drill string; and

When the drop is detected, it is confirmed that the uphole mud pressure remains constant while the drill string advances to increase confidence in the detection of the potential cross-hole.

Concept 35. The method according to Concepts 26-34, further comprising:

After issuing the warning, at least one data record characterizing the potential intersection hole is sent.

Concept 36. The method of Concepts 26-35, wherein the drill string defines a passage for carrying a pressurized flow of drilling mud from the drill rig to the drill tool during advancement of the drill tool to discharge the drilling mud from the drill tool, the method further comprising:

Correlating the drill bit force to downhole mud annulus pressure surrounding the drill tool; and

At least a decrease in the downhole mud annulus pressure corresponding to a decrease in the drill bit force is confirmed.

Concept 37. An apparatus for use in conjunction with a horizontal directional drilling system, the horizontal directional drilling system comprising a drill string having a length extending from a drilling rig to a drill tool having a drill bit, wherein extension of the drill string advances the drill tool through the ground during a drilling operation to form a pilot hole, the apparatus comprising:

a monitoring device for monitoring a drill bit force exerted by the drill bit on a pilot hole face during advancement of the drilling tool;

a sensor for detecting a drop in the drill bit force; and

A processor is configured to initiate a response based at least in part on detecting the dip as an indication of a potential intersecting hole.

Concept 38. In a system for conducting inground operations and utilizing at least a portable detector and a drill string extending from a drill rig to an inground tool as at least one of a homing beacon and a tracking device, a communication system comprising:

an uphole transceiver located at the drilling rig;

a downhole transceiver located downhole near the buried tool;

a portable transceiver forming part of the lightweight locator;

a first bidirectional communication link between the uphole transceiver and the downhole transceiver using the drill string as an electrical conductor to provide communication between the uphole transceiver and the downhole transceiver; and

A second two-way communication link between the portable transceiver of the portable detector and the downhole transceiver adopts wireless electromagnetic communication between the portable transceiver of the portable detector and the downhole transceiver, so that information generated by the portable detector can be sent to the uphole transceiver by sending the information from the portable detector to the downhole transceiver via the second two-way communication link, and then by sending the information from the downhole transceiver to the uphole transceiver via the first two-way communication link.

Concept 39. The communication system of Concept 38, further comprising:

a telemetry link for two-way communication between the portable detector and the uphole transceiver; and

a processor configured to at least temporarily redundantly transmit a given signal between the downhole transceiver and the uphole transceiver when the first bidirectional communication link is used as a first redundant transmission and in cooperation with a second redundant transmission, wherein the second redundant transmission uses the telemetry link and the second bidirectional communication link so that the second redundant transmission passes through a portable detector.

Concept 40. The communication system of Concept 39, wherein said processor is configured to arbitrate between said redundant transmissions and thereafter select an optimal transmission route based on said first redundant transmission and said second redundant transmission.

Concept 41. The communication system of Concept 40, wherein said processor is configured to select an optimal transmission route based on a transmission bandwidth of each of said first redundant transmission and said second redundant transmission.

Concept 42. The communication system of Concepts 39-41 wherein said processor is configured to maintain a first data transmission corresponding to said first redundant data transmission and a second data transmission corresponding to said second redundant transmission.

Concept 43. The communication system of Concept 42 wherein said processor is configured to arbitrate between different data types of said first and second data transmissions to increase an overall bandwidth of said communication system.

Concept 44. A method for use in conjunction with a horizontal directional drilling system, the horizontal directional drilling system comprising a drill string extending from a drill rig to an inground tool such that extension of the drill string integrally produces corresponding movement of the inground tool through the subsurface during inground operations, the drill string defining a passageway for carrying a pressurized flow of drilling mud from the drill rig to the drill tool for discharge from the drill tool, the method comprising:

detecting that the uphole mud pressure is at or above an uphole mud pressure threshold;

In response to detecting that the uphole mud pressure is at or above the uphole mud pressure threshold, determining a current value of a downhole mud annulus pressure in an annular region around the drill tool;

comparing a current value of the downhole mud annulus pressure with a downhole mud pressure threshold;

determining a current mud flow rate through the drill string in response to the current value of the downhole mud annulus pressure being at or below the downhole mud pressure threshold;

comparing the current mud flow rate with a mud flow rate threshold; and

In response to the current mud flow being at or below the mud flow threshold, a response is initiated.

Concept 45. The method of Concept 44, wherein initiating said response comprises at least one of issuing a nozzle blockage warning and at least automatically temporarily pausing operation of said drilling rig.

Concept 46. The method according to Concept 45 or 46, further comprising:

Input controls are displayed to the operator to allow the operator to clear the nozzle clog warning.

Concept 47. The method according to Concept 45, further comprising:

Input controls are displayed to the operator to allow the operator to record the nozzle clog warning.

Concept 48. An apparatus for use in conjunction with a horizontal directional drilling system, the horizontal directional drilling system comprising a drill string extending from a drill rig to an inground tool such that extension and retraction of the drill string during inground operations collectively produce corresponding movement of the inground tool through the subsurface, the drill string defining a passageway for carrying a pressurized flow of drilling mud from the drill rig to the inground tool for discharge from the inground tool, the apparatus comprising:

a sensor device for monitoring each of uphole mud pressure at the drilling rig, downhole mud annulus pressure existing in the ground surrounding the inground tool, and mud flow rate of the drilling mud within the passageway of the drill string;

A processing device, comprising:

detecting an uphole mud pressure at or above an uphole mud pressure threshold;

In response to detecting that the uphole mud pressure is at or above an uphole mud pressure threshold, determining a current value of a downhole mud annulus pressure in the ground surrounding the inground tool;

comparing a current value of the downhole mud annulus pressure with a downhole mud pressure threshold;

determining a current mud flow rate through the drill string in response to the current value of the downhole mud annulus pressure being at or below the downhole mud pressure threshold;

comparing the current mud flow rate with a mud flow rate threshold; and

Based on the current mud flow being at or below the mud flow threshold, a response is initiated.

Concept 49. A method for use in conjunction with a horizontal directional drilling system, the horizontal directional drilling system comprising a drill string having a length extending from a drilling rig to an inground tool for performing inground operations, the drill string moving the inground tool along a path through the ground, the motion of the drill string being characterized at least in part by a pitch orientation of the inground tool, the method comprising:

measuring the motion of the drill string to characterize the motion as a series of incremental movements of the inground tool based on a length of the drill string;

establishing a pitch orientation of the inground tool associated with each incremental motion;

determining an incremental depth change along the depth of the inground tool for each incremental movement such that each incremental movement serves as a pitch measurement interval; and

The incremental depth changes are summed as part of determining a current depth of the inground tool at a current location.

Concept 50. The method of Concept 49, wherein said measuring is based on a length of said drill string.

Concept 51. The method of Concept 49 or 50, wherein said measuring is performed during advancement of said inground tool away from said drilling rig.

Concept 52. The method of Concept 49, 50, or 51, wherein said measuring is performed during retraction of said inground tool toward said drilling rig.

Concept 53. The method according to Concepts 49-52, further comprising:

The incremental motions are spaced an amount such that bending of the drill string is negligible.

Concept 54. The method according to Concepts 49-53, further comprising:

The incremental depth change is determined based on the assumption that the inground tool follows a straight line segment for each incremental movement.

Concept 55. The method according to Concepts 49-54, further comprising:

transmitting the respective pitch orientations to the drill rig by using the drill string as an electrical conductor to demonstrate throughput for transmission; and

A pitch measurement interval for a series of incremental movements is modified based on the throughput.

Concept 56. The method according to Concepts 49-55, further comprising:

transmitting the respective pitch orientations and other data traffic to the drill rig via a drill string communication system using the drill string as an electrical conductor to demonstrate throughput for transmission; and

The pitch measurement interval for a series of incremental movements is varied based on the current flow of the drill string communication system.

Concept 57. The method according to Concepts 49-56, further comprising:

The frequency of the pitch measurement interval is modified in proportion to the offset of the inground tool from a horizontal orientation.

Concept 58. The method according to Concepts 49-57, further comprising:

The frequency of the pitch measurement interval is modified based on the current pitch value of the inground tool.

Concept 59. The method of Concept 57, further comprising:

The frequency of the pitch measurement intervals is modified in proportion to an increasing rate of change of the pitch of the inground tool.

Concept 60. The method of Concepts 49-59, further comprising:

The drill rig is automatically temporarily paused in response to obtaining the respective pitch orientation.

Concept 61. An apparatus for use in conjunction with a horizontal directional drilling system, the horizontal directional drilling system comprising a drill string having a length extending from a drilling rig to an inground tool for performing inground operations, the drill string moving the inground tool along a path through the ground, the movement of the drill string being characterized at least in part by a pitch orientation of the inground tool, the apparatus comprising:

a counter at the drilling rig for measuring a series of incremental movements of the inground tool based on a length of the drill string;

a pitch sensor at the inground tool for establishing a pitch orientation of the inground tool associated with each incremental movement; and

A processor is configured to determine an incremental depth change along the inground tool depth for each incremental movement such that each incremental movement serves as a pitch measurement interval, and sum the incremental depth changes as part of determining a current depth of the inground tool at a current location.

Concept 62. A method for use in conjunction with a horizontal directional drilling system during inground operations, the inground operations including a pullback operation in which a drill string is pulled back by a drill rig to pull a utility at least generally along a pilot hole, thereby potentially creating a keyhole situation in which the utility is inadvertently displaced above an initial path of the pilot hole, the method comprising:

while measuring a length of the drill string extending from the drill rig to a drill tool, advancing the drill tool through the ground to form the pilot hole in response to extension of the drill string from the drill rig;

recording at least one parameter characterizing the guide bore at a series of locations along the guide bore as the drill tool advances, the parameter being represented by a measured length of the guide bore for each location in the series of locations;

After forming the pilot hole, attaching a pullback tool to the distal end of the drill string and attaching the utility to the pullback tool;

during a pullback operation, retracting the drill string to pull the pullback tool and the utility at least generally along the pilot bore toward the drill rig while measuring a length of the drill string extending from the drill rig to the pullback tool;

characterizing at least a current value of said parameter represented by a measured length of said drill string during retraction;

comparing a current value of a parameter obtained at a current position of the pullback tool during a pullback operation with a recorded value of the parameter obtained during forming the pilot hole and corresponding to the current position; and

Based on a deviation of the current value of the parameter from the recorded value, a response to at least the potential occurrence of drill string keyholing is initiated.

Concept 63. The method of Concept 62, wherein characterizing the current value of the parameter during retraction comprises sensing different parameters during retraction and generating the current value of the parameter based on the sensed values of the different parameters.

Concept 64. The method of Concept 63, wherein the parameter is inground depth and the different parameter is a pitch orientation of the inground tool during a pullback operation.

Concept 65. The method of Concepts 62-64, wherein initiating said response comprises issuing a notification of at least the potential occurrence of drill string keyholing.

Concept 66. The method of Concepts 62-65, wherein initiating said response comprises pausing operation of said drilling rig.

Concept 67. The method of Concepts 62-66, wherein the parameter is pitch orientation and the comparing step is comparing the difference between the current value and the recorded value of the pitch orientation with a threshold pitch change amount to initiate the response each time the difference between the current value and the recorded value exceeds the threshold pitch change amount.

Concept 68. The method of Concept 67, wherein said threshold pitch change amount is 1 degree or less.

Concept 69. The method of Concepts 62-68, further comprising:

The comparing step is repeated in substantially real time as the current position of the pullback tool advances at least approximately along the pilot hole toward the drilling machine.

Concept 70. The method of Concepts 62-69, wherein the parameter is depth, and wherein the comparing step is comparing the difference between the current and recorded depth values to a depth change threshold to initiate the response when the difference between the current and recorded depth values exceeds the depth change threshold.

Concept 71. The method of Concept 70 wherein said depth change threshold is 2 feet or less.

Concept 72. The method of Concepts 62-71, wherein the drill string extends from the drill rig to the pullback tool to perform a pullback operation to move the pullback tool through the subsurface, the movement of the drill string being characterized at least in part by a pitch orientation of the pullback tool, the method further comprising:

measuring a series of incremental movements of the inground tool based on a length of the drill string during a pullback operation;

establishing a pitch orientation of the pullback tool associated with each incremental motion;

determining an incremental depth change along the pullback tool depth for each incremental movement serving as a pitch measurement interval; and

The incremental depth changes are summed as part of determining a current depth of the pullback tool at a current location.

Concept 73. The method of Concepts 62-72, further comprising:

During forming the pilot hole, obtaining at least one pilot hole confidence point depth reading; and

During a pullback operation, an operator of the system is prompted to obtain at least one corresponding pullback confidence point depth reading for comparison with the pilot hole confidence point depth reading.

Concept 74. The method of Concept 73, wherein said pilot hole confidence point depth reading and said corresponding pullback confidence point depth reading are obtained using a lightweight locator.

Concept 75. The method of Concepts 62-74, wherein said parameter is the position of said drilling tool and said pullback tool.

Concept 76. An apparatus for use in conjunction with a horizontal directional drilling system during inground operations, the inground operations including a pullback operation in which the drill string is pulled back by the drill rig to pull a utility at least generally along a pilot hole, thereby potentially creating a keyhole situation in which the utility is inadvertently displaced above an initial path of the pilot hole, the apparatus comprising:

a drill rig monitoring device for measuring the length of the drill string (i) during formation of the pilot hole by advancing the drill tool through the ground in response to extension of the drill string from the drill rig while measuring the length of the drill string, and (ii) during a pullback operation for installing the utility underground; and

The controller is constructed as follows:

During forming the guide hole, recording at least one parameter characterizing the guide hole represented by the measured length,

characterizing at least the parameter at the pullback tool as the drill string is retracted to pull the pullback tool and the utility toward the drilling rig at least generally along a guide bore represented by a measured length of the drill string during a pullback operation,

comparing the current value of the parameter during the pullback operation with the recorded value of the parameter, and

Based on a deviation of the current value of the parameter from the recorded value, a response to at least the potential occurrence of drill string keyholing is initiated.

Concept 77. A method for use in conjunction with a horizontal directional drilling system comprising a drill string extending from a drilling rig to a drill tool having a drill bit, such that extension of the drill string during a drilling operation advances the drill tool through the subsurface to form a pilot hole, the method comprising:

performing notch spacing by advancing the drill string while rotating the drill bit from a starting angular position to an ending angular position less than one full revolution to engage the drill bit with the end face of the pilot hole;

retracting the drill string in cooperation with sensing a drill bit force acting on an end face of the pilot hole by the drill bit;

rotating the drill string in coordination with terminating the retraction based on the sensed drill bit force to return the drill bit to the starting angular position such that the drill bit force acting on the pilot hole end face is at least partially relieved; and

Repeat the above steps to perform one or more automatic grooving iterations.

Concept 78. The method of Concept 77, further comprising:

Before starting to execute the carving interval, input parameters are accepted, including an automatic carving range having a start position and a stop position, a target pitch orientation and/or a target yaw orientation, and an iteration number of the carving interval.

Concept 79. The method of Concept 78, wherein said input parameters are accepted as default values.

Concept 80. The method of Concept 78 wherein said input parameters are operator defined.

Concept 81. The method of Concepts 78-80, wherein said input parameters further include thrust and rotational speed.

Concept 82. The method of any of Concepts 77-81, wherein said retracting is terminated in response to detecting that a drill bit force acting on an end face of said pilot hole has eased.

Concept 83. The method of Concept 82, wherein said retracting is terminated prior to said step of rotating the drill string to return said drill bit to said starting angular position.

Concept 84. The method of Concepts 77-83, further comprising:

Any further iterations of the method are terminated in response to detecting that the target parameter has been achieved.

Concept 85. The method of Concept 84 wherein said target parameter is a target pitch orientation and said method comprises sensing the pitch orientation of said drill tool outside of said notch intervals to improve the data accuracy of the pitch orientation for comparison with said target pitch orientation.

Concept 86. The method of Concept 84 or 85, wherein the target parameter is a target deflection orientation, and the method includes sensing the deflection orientation of the drill tool outside of the groove spacing to improve the data accuracy of the deflection orientation for comparison with the target deflection orientation.

Concept 87. The method of Concepts 77-86, further comprising:

comparing the target parameters with the current parameters for the current iteration;

Recognizing that the target parameter has not yet been obtained;

Accumulating current iteration data with data from at least one previous iteration to generate accumulated data for comparison with the target parameter;

Determining whether the accumulated data and the current iteration data are gradually approaching the target parameter; and

If the accumulated data and the current iteration data are gradually approaching the target parameter, another iteration is performed, otherwise it is indicated that the iteration should be terminated because the accumulated data and the current iteration data are deviating from the target parameter.

Concept 88. The method of Concepts 77-87, further comprising:

comparing the target parameters with the current parameters for the current iteration;

identifying that the target parameter has not been obtained;

determining that advancement of the drilling tool in a specific direction other than a target direction is achievable; and

A notification is issued to the operator to at least inform the operator that progress in the particular direction is available.

Concept 89. The method of Concept 88, wherein said issuing step comprises providing at least one of a revised target and a set of revised endpoints for a groove spacing to be performed during a new set of iterations based on said particular direction.

Concept 90. The method of Concepts 77-89, further comprising:

repeatedly transmitting roll orientation reading updates from the drill tool to the drill rig during operation of the system and transmitting other data between the drill tool and the drill rig via a drill string communication system using the drill string as an electrical conductor; and

In response to initiating execution of the carving interval, additional bandwidth of the drill string communication system is allocated to rolling orientation updates relative to other data, and the allocation of additional bandwidth is maintained at least until the automatic carving iteration has completed.

Concept 91. The method of Concept 90, further comprising:

repeatedly transmitting pitch orientation reading updates from the drill tool to the drill rig during operation of the system and transmitting other data between the drill tool and the drill rig via a drill string communication system using the drill string as an electrical conductor; and

In response to detecting that the drill tool is stationary after initiating execution of the carving interval, further allocation of drill string communication system bandwidth is invoked for roll orientation updates, and otherwise allocated to pitch orientation reading updates.

Concept 92. An apparatus for use in conjunction with a horizontal directional drilling system including a drill string extending from a drilling rig to a drill tool having a drill bit, such that extension of the drill string during a drilling operation advances the drill tool through the subsurface to form a pilot hole, the apparatus comprising:

a drill bit force sensor for sensing the drill bit force exerted by the drill bit on the end face of the pilot hole; and

The controller is constructed as follows:

performing notch spacing by advancing the drill string while rotating the drill bit from a starting angular position to an ending angular position less than one full revolution to engage the drill bit with the pilot hole end face,

retracting the drill string in cooperation with sensing a drill bit force acting on the end face of the pilot hole,

rotating the drill string in coordination with terminating the retraction based on the sensed drill bit force to return the drill bit to the starting angular position such that the drill bit force acting on the pilot hole end face is at least partially relieved, and

The executing step, the retracting step, and the rotating step are repeated at least once.

Concept 93. A method for use in conjunction with a horizontal directional drilling system, the horizontal directional drilling system comprising a drill string extending from a drill rig to an inground tool, such that extension and retraction of the drill string during inground operations collectively produces corresponding movement of the inground tool, the method comprising:

sensing a downhole parameter representative of the buried tool;

sensing an uphole parameter indicative of at least one operating condition at the drilling rig; and

A response to the detection of at least one adverse operating condition is automatically initiated based on the downhole parameter and at least in part on the uphole parameter.

Concept 94. The method of Concept 93, wherein said detrimental operating condition is one of potential fracture leakout, potential cross-bore, potential drill string keyhole, and excessive downhole mud annulus pressure.

Concept 95. An apparatus for use in conjunction with a horizontal directional drilling system, the horizontal directional drilling system comprising a drill string extending from a drilling rig to an inground tool, such that extension and retraction of the drill string during inground operations collectively produces corresponding movement of the inground tool, the apparatus comprising:

a downhole sensor for sensing a downhole parameter representing the buried tool;

an uphole sensor for sensing an uphole parameter indicative of at least one operating condition at the drilling rig; and

A processor is configured to automatically initiate a response to the detection of at least one adverse operating condition based on the downhole parameter and at least in part on the uphole parameter.

Concept 96. In a system for performing inground operations and utilizing at least a drill string and a portable locator, the drill string extending from a drilling rig to an inground tool, the portable locator being configured to receive at least a locating signal transmitted from the inground tool, a communication system comprising:

an uphole transceiver located near the drilling rig;

a portable transceiver forming part of the lightweight locator and configured to receive the locating signal to at least periodically update a depth reading of the inground tool;

a telemetry link for at least two-way communication from the portable transceiver of the portable locator to the uphole transceiver via portable locator telemetry signals to at least periodically transmit the depth readings to the uphole transceiver; and

A processor is configured to monitor the telemetry link to detect signal attenuation of the portable locator telemetry signal and, in response to detecting the signal attenuation, switch periodic transmission of depth readings to a different communication path for receipt by the uphole transceiver.

Concept 97. The communication system of Concept 96, further comprising:

The portable transceiver of the portable detector is further configured to transmit an underground communication signal that is received by the underground tool to form an underground communication link; and

a downhole transceiver supported by the inground tool for transmitting the positioning signal, wherein the downhole transceiver bidirectionally communicates with the uphole transceiver by using the drill string as an electrical conductor to provide communication between the uphole transceiver and the downhole transceiver, thereby acting as a bidirectional communication link, wherein the different communication paths include the inground communication link and the bidirectional communication link.

Concept 98. A communication system according to Concept 97, wherein the processor is located at the drilling rig and is further configured to generate a prompt in response to detecting attenuation of a signal transmitted to the inground tool via at least the bidirectional communication link, and the inground transceiver is configured to forward the prompt to the portable device to instruct the portable device to thereafter transmit at least periodic depth readings to the inground tool via the inground communication link for subsequent transmission to the uphole transceiver via the bidirectional communication link.

Concept 99. The communication system of Concept 98 wherein said telemetry link is bidirectional and said processor is further configured to transmit said prompt to said portable device via said telemetry link such that a pair of redundant communication paths are available for said prompt.

Concept 100. The communication system of Concept 97 wherein the processor is located at the drill rig and is further configured to generate an alert as an indication of attenuation of a signal sent to the inground tool, and wherein the telemetry link is bidirectional, and wherein the processor is configured to transmit at least the alert to the portable device via the telemetry link to instruct the portable device to thereafter transmit at least periodic depth readings to the inground tool via the inground communication link for subsequent forwarding to the uphole transceiver via the bidirectional communication link.

Concept 101. The communication system of Concept 97 wherein said processor is further configured to at least periodically generate an acknowledgment in response to receiving data from said portable locator via said telemetry link and configured to transmit said acknowledgment for receipt by said portable locator.

Concept 102. The communication system of Concept 101 wherein said portable locator is configured to monitor said periodic receipt of said acknowledgments and to switch to said different communication path in response to at least one missing acknowledgment.

Concept 103. The communication system of Concept 101 or 102 wherein said processor is configured to send said confirmation to said portable detector and to send said positioning signal via said bidirectional communication link.

Concept 104. The communication system of Concept 102 wherein said telemetry link is bidirectional and said processor is configured to transmit said confirmation to said portable detector via said telemetry link.

Concept 105. The communication system of Concepts 96-104 wherein said processor is configured to monitor at least one characteristic of said lightweight telemetry signal to detect signal degradation.

Concept 106. The communication system of Concept 105 wherein said characteristic is at least one of a signal-to-noise ratio, a bit error rate, and a packet loss rate.

Concept 107. In a system for performing inground operations and utilizing at least a drill string extending from a drilling rig to an inground tool and a portable locator for receiving at least a locating signal transmitted from the inground tool, a method comprising:

placing an uphole transceiver near the drilling rig;

configuring a portable transceiver to form part of the lightweight locator to receive the locating signal to at least periodically update a depth reading of the inground tool;

forming a telemetry link for at least bidirectional communication from the portable transceiver of the portable locator to the uphole transceiver via portable locator telemetry signals to at least periodically transmit the depth readings to the uphole transceiver;

automatically monitoring the telemetry link to detect signal degradation of the portable locator telemetry signal; and

In response to detecting the signal attenuation, periodic transmission of depth readings is switched to a different communication path for receipt by the uphole transceiver.

Claims (16)

1. A method for use in conjunction with a horizontal directional drilling system, the horizontal directional drilling system comprising a drill string extending from a drilling rig to a burial tool, such that during burial operations, the extension and retraction of the drill string collectively generate a corresponding movement of the burial tool, the drill string defining a channel for carrying pressurized flow of drilling mud from the drilling rig to the burial tool to discharge the drilling mud from the burial tool, the method comprising: During the burial operation, monitor the mud annulus pressure in the ground surrounding the burial tool; The decrease in the mud annular pressure was detected; After the decrease is detected, the mud annular pressure is monitored again to monitor its recovery, thereby defining a negative pulse in the mud annular pressure; and Initiate a response as an indication of a potential crosshole. 2. The method of claim 1, wherein the response step includes issuing a warning to indicate the potential crosshole. 3. The method of claim 2, wherein the issuing step requires detecting the drop in conjunction with detecting the wellbore mud pressure based on a wellbore mud pressure threshold, detecting the mud flow rate based on a flow rate threshold, and detecting the movement of the drill string. 4. The method according to claim 1, further comprising: Supplementary data is collected in response to the detection of the decrease during the time interval before and/or after the decrease is detected. 5. The method according to claim 4, wherein the supplementary data includes surface mud pressure, downhole mud pressure, and mud flow rate. 6. The method according to claim 5, further comprising: Additional data, including at least one of drill string length and drill string push/pull rate, are collected within an optional time interval based on a first time point when the drop is detected and a second time point when the recovery is detected. 7. The method according to claim 6, further comprising: The optional time interval is defined based on the offset, such that the first time point is before the decrease in mud annulus pressure, and the second time point is after the recovery of the downhole mud pressure. 8. The method according to claim 1, further comprising: If the recovery is not detected, a response is issued as an indication of potential fracturing leakage. 9. The method according to claim 1, further comprising: In response, the operation of the drilling rig is automatically paused. 10. The method according to claim 1, further comprising: During normal operation of the drilling rig, a minimum threshold for the mud annulus pressure is established based on hydrostatic pressure, and the response is initiated based on this minimum threshold. 11. The method of claim 1, wherein the step of initiating the response further requires detecting the descent in conjunction with detecting the movement of the drill string. 12. The method according to claim 1, further comprising: During the burial operation, a gas sensor is used to monitor one or more gases in an annular area around the burial tool, including natural gas, propane, hydrocarbon gases, and sewer gases. 13. The method according to claim 1, further comprising: During underground operations, gas sensors are monitored to detect one or more gases near the drilling rig, including natural gas, propane, hydrocarbon gases, and sewer gases. 14. A method for use in conjunction with a horizontal directional drilling system, the horizontal directional drilling system including a drill string extending from a drilling rig to a burial tool, such that during burial operations, the extension and retraction of the drill string collectively generate a corresponding movement of the burial tool, the drill string defining a channel for carrying pressurized flow of drilling mud from the drilling rig to the burial tool to discharge the drilling mud from the burial tool, the method comprising: During the burial operation, monitor the mud annulus pressure in the ground surrounding the burial tool; The decrease in the mud annular pressure was detected; The response is initiated at least in part based on the detection of the drop as an indication of either a potential cross-hole or a potential fracturing leak; The rate of change of the decrease in the mud annular pressure was measured; and The rate of change is used to distinguish between the potential cross-hole and the potential fracturing leak in order to initiate the response. 15. The method of claim 14, further comprising selecting a threshold for the rate of change of the decrease in the mud annular pressure within the range of -20 psi/s to -100 psi/s, and the distinguishing step comparing the measured rate of change with the selected threshold. 16. An apparatus for use in conjunction with a horizontal directional drilling system, the horizontal directional drilling system including a drill string extending from a drilling rig to a burial tool, such that during burial operations, the extension and retraction of the drill string collectively generate a corresponding movement of the drill string through the ground, the drill string defining a channel for carrying pressurized flow of drilling mud from the drilling rig to the burial tool to discharge the drilling mud from the burial tool, the apparatus comprising: A sensor, used to sense the mud annular pressure in the ground surrounding the burial tool during burial operations to generate a sensor output; and The processor receives the sensor output and is configured to monitor the mud annular pressure based on the sensor output, and after detecting a drop in the mud annular pressure, to continue monitoring the mud annular pressure in order to monitor its recovery, thereby defining a negative pulse in the mud annular pressure and issuing a warning in response to the recognition of the negative pulse.