Pipeline following sensor arrangement

A method and apparatus for installing a monitoring cable or other utility near an existing pipeline. An electromagnetic signal may be induced on the pipeline, either directly, or by transmitting a signal from a vehicle carrying a sensor array. The sensors disposed on the vehicle communicate with a processor to determine a distance and orientation of the vehicle relative to the pipeline. The signal may be electromagnetic, acoustic, capacitive, or the like. A plow or other digging tool may be on the vehicle or a secondary vehicle. Such a digging tool opens a trench and installs the cable along a path disposed next to the pipeline within an acceptable distance range from the pipeline. The vehicle may be remotely or automatically operated.

FIELD

The present invention relates generally to an apparatus and method for installing a monitoring cable proximate an in-situ pipeline.

SUMMARY

The present invention is directed to an apparatus for installing a line along a length of buried pipeline. The apparatus comprises a machine frame, a plow, a first proximity sensor, and a second proximity sensor. The machine frame comprises at least one ground engaging drive member, and defines a first and second end and longitudinal centerline. The plow is disposed on the second end of the frame. The first and second proximity sensors are longitudinally spaced and both capable of detecting an electromagnetic field emanating from the buried pipeline.

The present invention is further directed to a method. The method comprises inducing an electromagnetic signal on a length of buried pipeline and translating a mobile machine along the length of the buried pipeline. The magnetic signal is detected at the mobile machine frame as it translates along the length of pipeline. The signal is used to maintain the machine frame along a path a desired distance range away from the buried pipeline. The method further comprises opening a trench along the path as the machine frame is translated along the length of the pipeline and installing a line within the trench.

The invention is further directed to a system comprising a pipeline, a monitoring line, and a processor. The monitoring line is disposed at a distance of less than ten feet from the pipeline and carries a signal along its length. The processor is in communication with the monitoring line and detects interruptions or abnormalities in the signal. The monitoring line and pipeline are at least partially underground. At the onset of the second residence time, the pipeline contains a flowing material.

DETAILED DESCRIPTION

Pipelines transmit a flowing material, such as water, crude oil or natural gas, from one location to a distant location. Such pipelines must be monitored to detect leaks, nearby digging activity, and the like. Pressurized liquid or gas may rapidly expand from any breach of the pipeline. Leaks could cause environmental damage and loss of valuable product, and could lead to safety hazards. Any digging activity that does not take particular care to avoid the pipe risks causing the same hazards.

In recent years, monitoring systems have been developed to remotely monitor a condition of the pipeline, which may include leaks and nearby digging. For example, fiber optic cable or other sensor lines, laid along the length of a pipeline, carry a signal between spaced nodes. When the signal is interrupted or distorted, software interprets that disruption to determine the nature and location of a hazard. Such real-time monitoring can allow quick mitigation of the hazard.

While new installations of pipelines allow for easy installation of such monitoring lines during the installation process, many thousands of miles of such pipelines exist without monitors. The present invention provides a way to install monitors, such as fiber-optic monitoring lines, next to pre-existing pipelines.

Much of the difficulty in such installation is due to the nature of oil and gas pipelines. Pipelines are typically installed with 3 to 6 feet of groundcover. Oil pipelines range in diameter from 6 to 48 inches. Gas pipelines range in diameter from 16 to 48 inches, and may be at 200 to 1500 psi. While maps of active lines typically exist, vital data, such as the diameter of the pipe, its exact position, exact depth, lateral junctions, y- and t-joints left for expansion, location of curves, etc., may not be included. Additionally, what data there is may be rendered unreliable by uncertainty, soil erosion, or migration of the pipe due to the passage of time.

Thus, whether a pipeline has been installed 6 months, 10 years, or half a century prior to an installation, any installation of a monitoring line next to a pipeline is problematic for several reasons.

Additionally, to be effective, fiber lines should be installed from approximately 18 inches to 3 feet away from the pipeline. Urban and suburban utility easements may limit the maximum separation possible. For gas lines, the preferred installation position for leak detection may be at 10 o'clock or 2 o'clock relative to the pipeline. For oil lines, the preferred position may be at 5 o'clock or 7 o'clock. The optimal position for detecting digging may be directly above the pipeline. In each of these cases, a monitoring line will be less effective with distance from the pipeline.

Fiber lines and similar monitoring lines may be installed by conventional vibratory plows, trenchers, horizontal directional drills and other methods. However, as detailed above, the underground pipe's location is unpredictable and an inadvertent strike of the line could be catastrophic.

A charge or electromagnetic signal may be induced on the oil or natural gas pipeline, as many of these pipelines are made of a conductive material, like steel. When made of non-conductive material such as plastic, a tracer wire is buried alongside the pipeline to facilitate pipeline location by inducing a charge or signal on the wire. A signal transmitter may be attached to such tracer wire or conductive pipelines to impress or induce a signal along its length. Such active locating causes a pipe to be “illuminated” such that locating devices can detect the signal as it emanates from the pipe.

Due to the relatively large diameters of some oil and gas pipelines, and the relatively close distance at which a monitoring line needs to be installed, an “illuminated” pipe may appear less like a filament and more like a surface to locating device. Additionally, tees, elbows, pipe taps and other anomalies may render the pipe non-cylindrical in stretches. Thus, error will be associated with an estimated centerline or an estimated outside edge of a detected pipe. The system disclosed herein accounts for such error when installing a monitoring line near a previously installed pipeline.

With reference toFIG.1, an apparatus for installing a line substantially parallel to an existing pipeline is shown. An installation machine10is shown installing a monitoring cable12proximate a buried pipeline13(FIG.2B). A footprint14of the buried pipeline13is projected on a surface of the ground. A centerline15of the buried pipeline13is likewise shown projected on a surface of the ground. It should be understood that the pipeline may be installed 3 to 6 feet beneath the footprint14.

The monitoring cable12may be of a type known in the industry to detect external hazards, leaks, or internal degradation of the pipeline. Such cables are typically fiber optic, though some cables may include specialized sensing cables or sensors which sense a physical change in pipeline operation. This physical change could be a leak, change in temperature, vibration or other physical phenomenon. In operation of the system, as shown inFIG.2A, signals are sent along the monitoring cable12from a first node16to a distant second node18. Typically, such a signal is a series of light pulses, though it could include electrical signals or other methods of communicating a change in physical state. It should be understood that a great many nodes may cooperate along a length of monitoring cable. Each node16,18may be up to a kilometer or more apart. Alternatively, said cable could be comprised of specialized sensors which detect one or more characteristics of improper pipeline operation spaced all along the cable.

The second node18sends data indicative of the received signal to a monitoring processor20. The monitoring processor20analyzes the received signal for a change in pipeline operation indicating an interruption or distortion. Such an interruption or distortion will determine the location and nature of a hazard. Remedial or preventive measures may be taken at the precise location of the hazard.

As shown inFIG.2B, the pipeline13is disposed with the monitoring cable12at approximately the 2 o'clock position. The cable12is a distance17away from the edge of pipeline13. This distance17should be within a range between a maintained minimum gap and maximum distance. The maximum distance between the pipeline13and monitoring cable12to allow the cable12to be effective may be between 1.5 and 3 feet. Other lengths, such as 6 to 10 feet, may also be feasible. Likewise, for new monitoring cable installations, a minimum gap to minimize the risk of a strike between installation devices and the pipeline13may be between 12 and 24 inches.

In prior art systems, the monitoring cable12and pipeline would need to be installed at the same time. This is due to difficulties in installing a monitoring cable12underground near the footprint14of a previously buried pipeline. However, due to the installation machine10, a monitoring cable12may be installed in proximity to a pipeline with a residence time of more than six months to a year. In some instances, pipelines will have been in place for decades prior to installation of the monitoring cable12.

With reference again toFIG.1, the installation machine10comprises a frame21. The frame21has a front end22, a rear end24, and a longitudinal axis26disposed along its centerline. The machine frame21is translated across a surface of the ground by one or more ground drive members27. As shown, the installation machine10comprises four tracks.

The installation machine10comprises a plow assembly30disposed at the rear end24along the longitudinal axis. The plow assembly30comprises a plow blade32(FIGS.3A-3C), a vibrator assembly34, and a cable guide35. The vibrator assembly34imparts a vibration to the plow blade32to open a trench for placement of the monitoring cable12. The cable guide35provides a channel36for feeding the monitoring cable12into the trench.

The installation machine10further comprises at least one sensor40disposed on the frame. Preferably, the installation machine10comprises a plurality of sensors. The plurality of sensors40may be spaced longitudinally relative to the frame21. The sensors40may alternatively, or in addition, be spaced laterally about the frame21or vertically relative to the surface of the ground.

In any case, sensors40are operatively connected to a processor100. The processor100analyzes signals received by the sensors40as will be further described below, and uses those signals to determine the distance and orientation of the pipeline relative to the plow, and display or make operational or steering adjustments in response. The processor100may be included onboard the machine10as shown inFIG.1, or may be remote. The processor100may control the machine10directly, or may provide information to an operator at an operator station102located on the machine frame21or a remotely located operator at a distant point removed from the machine.

The sensors40may be magnetometers, magnetoresistive devices, triaxial ferrite rods, triaxial air core antennas, or similar sensing devices in controlled geometries. A single point electromagnetic field decomposition may be used to determine the relative orientation of the pipeline from the sensor40, but not necessarily separation distance. Using two or more spaced-apart sensors40may allow distance to be estimated and may provide steering input as the sensors40detect a change in the course of the footprint14. The processor100may then instruct the machine10to maintain a relatively constant distance from the footprint. Alternatively, distance may be displayed to a machine operator, who steers the tractor to maintain the desired distance. Alternatively, steering the plow assembly30relative to the tractor10may be used in conjunction with steering by the processor100. The sensors40may be calibrated to a representative pipe segment to improve distance estimates obtained from the processor100.

In one embodiment, shown inFIGS.1,2B,4,5, and7, an array of sensors40are disposed on a sensor outrigger42. The outrigger42is preferably positioned near the front of tractor10to provide distance input to processor100. Outrigger42may be separated from the frame21to decrease the influence of the frame's steel on the sensors40. The sensor outrigger42comprises a first arm44and a longitudinally spaced second arm46.

As shown, two sensors40are laterally spaced on the first arm44and two sensors are laterally spaced on the second arm46. The arms44,46of the sensor outrigger42may telescope to adjust the distance between sensors40. This will be advantageous when changing the offset distance between tractor10and the pipe centerline15. The outrigger42may alternatively comprise only one arm44, as shown inFIG.4. InFIG.4, the sensors40of the outrigger42are used in conjunction with a proximity sensor54disposed near the plow assembly30. Such configuration is shown in more detail inFIG.3A.

The outrigger42may be placed in line with the longitudinal axis26of the machine10, as shown inFIG.5. A front42A and rear42B outrigger are in line with the longitudinal axis26and the centerline15. Such a configuration may be advantageous for positioning the monitoring line12directly above the pipeline13. As shown inFIG.5, the pipeline13, as represented by centerline15, is turning to the left, necessitating a steering adjustment by the processor100.

InFIG.1, the outrigger42is cantilevered relative to the machine10such that sensors40are disposed away from the machine frame21on a single side of the longitudinal axis26and on each side of the footprint14. If the pipeline is magnetic or contains a conductive tracer wire, a locating signal may be placed on the pipeline by a transmitter29(FIG.2A). Locating transmitters may produce locating steady-state signals at a plurality of possible frequencies. Thus, the sensors40should be capable of detecting the signal at more than one frequency. As used herein, “steady-state” should be understood to mean a consistent signal, though such a steady-state signal may vary in predetermined or predictable ways to aid in identification. Such methods may include by changing magnitudes, pulsing the signal on and off, and varying the frequency.

The sensors40disposed on opposite sides of the centerline15of footprint14may coordinate to indicate equivalent but opposite or balanced readings. Such a result indicates that the footprint14is centered between opposing sensors40. The installation machine10may be steered as changes in the field are detected by the sensors40to maintain this “null” or balanced sensor40reading. By centering the footprint14and pipeline between a pair of sensors40, a minimum distance between the pipeline and the plow blade32may be maintained. Alternatively, sensors40may be offset from the centerline15and still measure the relative position of the centerline15.

While an outrigger42may be used with the installation machine10, a separate vehicle101(FIG.10) could contain the sensors described above. The separate vehicle101could either operate simultaneously with the installation vehicle10, or could create a record of the footprint14for later use by the installation vehicle. This record may be a physical marker, such as a paint line, or a virtual marker, such as GPS coordinates, virtual paint markers, or the like. The separate vehicle could communicate with the installation machine10via Bluetooth or similar communication methods to establish a preferred orientation when a monitoring cable12is being simultaneously installed. One such vehicle is shown in Provisional Application No. 62/943,579, from which this application claims priority, and which is incorporated by reference herein. The image atFIG.1thereof is appended hereto at Appendix A.

With continued reference toFIG.10, three sensors140A-C are arranged on a mobile frame103. The frame103is moved across a surface of the ground on motive elements such as wheels104. The sensors140A-C, as sensors40inFIGS.1-9, detect a signal emanating from the underground pipeline13. Alternatively, the frame103can be carried by an operator or mounted on a tractor or motorized cart. The three sensors140are maintained in a single plane by the frame103. While three sensors140, arranged linearly, are shown inFIG.10, other embodiments could have fewer or more sensors, or could be placed in a single plane but in a non-linear arrangement.

The vehicle101further comprises an inclinometer106. The inclinometer106measures the angle of the frame103relative to earth level, both left and right, front and rearward. Thus, deviations in the plane of the sensors140A-C from a level plane can be detected. A wheel position sensor no may be used to detect the changing position of the wheels104. The wheel position sensor110may provide data to determine distance traveled and velocity of the vehicle101.

Alternatively, or in cooperation with the wheel position sensor110, a global position sensor, such as a global navigation satellite sensor (GNSS) may be used to detect the absolute global position of the vehicle100, enabling mapping of the underground pipeline13.

The vehicle101may communicate with a processor100, located either onboard or off of the frame103. The sensors14A-C, inclinometer106, and wheel position sensor no collect data, which is sent to the processor100, as in the embodiment ofFIGS.1-9. The processor100gathers the outputs of the sensors140A-C and mathematically compares them to produce an overall measurement of an estimated position of the underground pipeline13. This position may be absolute, relative to the frame103, or both.

One advantage to using a separate vehicle101rather than an outrigger42is that errors, when detected, may be mitigated or investigated without concern for a simultaneous trenching project. Further, the separate vehicle101may endeavor to drive directly over a buried pipeline13, where an outrigger42may be limited in its position due to safety factors related to the uncovering of a trench.

When the frame103is a part of a moving vehicle, the processor100may be affixed to that vehicle. The operator may alternatively be remote. The output of the predicted location of the path of the pipeline13may be used to control the steering of the vehicle101. This control may occur autonomously or semi-autonomously. Alternatively, the output may be displayed to an operator who may make steering corrections, either from the vehicle101, or a remote location.

With reference now toFIGS.3A-3C, the plow blade32is shown in detail. The plow blade32comprises a blade edge50, a trailing edge52and a proximity sensor54. The blade edge50is the leading edge of the plow blade, and opens the trench. The trailing edge may include the cable guide35for installation of the monitoring line12within the opened trench.

The proximity sensor54may be of the same type as sensors40, or may be a ferrite rod or other antenna capable of detecting the transmitted steady-state signal emanating from the pipeline. Alternatively, sensor54may sense a physical property of pipe13such as a magnetic signal. InFIG.3A, the proximity sensor54is attached to the trailing edge52by a flexible or semi-rigid rod or cable56. The cable56is capable of transmitting received signals to the processor100.

FIG.3Bshows a sensor54formed within the plow blade32itself. As shown, a transmission cable58may be disposed within the blade32. This cable58may transmit signals to the processor100directly or through a wireless connection.FIG.3Cshows two vertically displaced proximity sensors54A and54B. Vertical displacement of a known distance may aid in detection of a distance from the pipeline from the plow blade32.

A suspended mass generator (not shown) or equivalent power source may be built into the plow blade32to provide power for the proximity sensor54and any corresponding electronics package in the blade structure.

The proximity sensor54is configured to provide an indication of separation from the pipeline. A generally decreasing separation distance, indicated by a strengthening received signal or other indicia, may indicate an approaching pipeline strike. The processor100may be configured to provide a minimum gap for the distance17(FIG.2B), subject to error tolerances. This gap may be from 12 to 18 inches or more. The processor100detects that the distance between the plow blade is less than the minimum gap. The gap indication may be presented to an operator of the installation machine10as a quantified distance. Alternatively, the installation machine10may be stopped or automatically steered away from the pipeline by the processor100.

Communication between the processor100, steering systems on the machine10, and the various sensors40,54may be provided by wireless methods, such as Bluetooth. Alternatively, communication may be to a remote operator location some distance away from machine10.

The plow blade32is preferably made of a non-magnetic alloy, such as Mangalloy, Nitronic 50 or Nitronic 60. Other such alloys may likewise be used. Further, pockets for installation of internal sensors such as inFIGS.3B and3Cmay be formed through laminar construction of the plow blade32. In such cases, the sensors54may be positioned in the pocket and sealed in place with a wear resistant material such as polyurethane. Non-metallic plow blades32will limit interference with the received transmission at the proximity sensor54.

The plow assembly30may comprise plow shoes, tires, or other devices to manually control the depth. The processor100may alternatively control plow depth based upon the detected position of the pipeline. In this configuration, the plow assembly30may be adjusted by a control system (not shown). The control system may comprise hydraulic cylinders (not shown) to control the maximum plow depth, and thus the depth of the trench in which the monitoring line12is installed. The control system responds to signals generated by the processor100to adjust plow depth based upon one or more factors such as pipe depth, blade depth, surface contour of the soil, plow location, position relative to an external laser plane, or others.

The sensors40and proximity sensor54may be responsive to cathodic protection signals commonly applied to metallic pipelines for reducing corrosion. Such a configuration allows existing pipeline signals to be used to locate the pipeline.

The installation machine10may be controlled remotely with the operator maintaining a distance from the footprint14of the pipeline. The machine10may follow a predetermined path, a paint line, a guide wire, or may be steered automatically due to the detected position of the pipeline.

With reference toFIGS.6A and6B, one or more proximity sensors54may be placed within a trencher boom70rather than a vibratory plow. The proximity sensors54may be placed within a restraint bar72(FIG.6A) or the trencher boom70itself (FIG.6B). As with the plow assembly30, the trencher boom70, restraint bar72, and trencher chain74may preferably be made of a nonmagnetic material to limit interference with the proximity sensors54.

Use of a triaxial magnetometer as one or all of the sensors40,54allows one of the three axes of the sensor40,54to be aligned with the longitudinal axis26. If the sensor40,54is near a filamentary conductor, this axial measurement will be null when the longitudinal axis26and the conductor are parallel. However, as the pipeline size increases, its field will not approximate a filament. Therefore, the use of several redundant sensors and measurements described herein will aid in maintaining a parallel installation of the monitoring cable12at a desired distance from the pipeline13.

With reference toFIG.7, the installation machine10ofFIG.1is shown with the pipeline13turning, necessitating a steering step. The processor100detects an electromagnetic field emanating from the pipeline13at at least four discrete points, a first and third sensor40A,40C disposed on the front arm44, and a second and fourth sensor40B,40D disposed on the rear arm46.

The sensors40A-D are disposed a known distance d away from each other on each respective arm44,46. Thus, each pair of sensors40A,40C and40B,40D is optimally a distance d/2 away from a position directly above the centerline15of the pipeline.

The processor100wishes to maintain the centerline15of the pipeline at equal distances from the first sensor40A and third sensor40C. However, inFIG.7sensor40C is closer to the centerline15than sensor40A. The departure from optimal is given as an error ε. The error ε is positive in the direction of40A and negative in the direction of40C.

The processor100may then determine a steering control response. As the error ε should be less than d/2. The steering control response can be illustrated by considering the case where two sensors40A-D are coplanar with a filamentary line. In such a case, the processor's steering response would be given by:

In a practical geometry, the response is complicated by the fact that the pipeline and sensors are not coplanar, and by the possibility that the pipeline has a diameter sufficiently large that it may not be treated as a filament. The general appearance of the steering response will, however, be similar in its general features to the mathematical relationship given above. In particular, a steering control will produce a signal when ε=0.

By detecting the error between sensors40A-D disposed both at the front arm44and rear arm46, the processor100will determine not only that a turn to the left is required, but also the magnitude of the steering correction in degrees based upon the errors in the front and rear sensors40A-D.

The sensor orientation ofFIG.7, especially if used in conjunction with other sensors, such as a proximity sensor54(FIG.5), may enable other “paired” sensors to create useful readings to aid the processor100in determining the position of the pipeline13and steering steps.

With reference toFIGS.11-14, the sensor140A-C orientation inFIG.10on the separate vehicle101allows for a method for estimating the pipeline13centroid170and error. While this method is shown with respect to three sensors140A-C, similar methods of estimating error may be used for the various embodiments of the invention.

Using this arrangement, the system determines three estimated locations150,152,154for the underground pipe13(or the centroid thereof) by triangulating the position of the signal using each pair of the three sensors140. For example, inFIG.11, estimated location150is detected by sensors140A,140B. InFIG.12, estimated location152is detected by sensors140B,140C. InFIG.13, estimated location154is detected by sensors140A,140C.

With reference toFIG.14, the three estimated locations150,152,154are plotted on a triangle156. The area of the triangle156represents the relative error in the locating operation. A centroid158of the triangle156represents the predicted location of the pipe13centroid given the three estimated locations150,152,154.

While triangulation is given as a method for finding the estimated locations, signal strength may alternatively be used to determine an estimated location at each antenna. These points could be plotted and a triangle156determined using this method as well. Various methods of calibration would be used to normalize the antennas relative to one another.

It is instructive to see inFIG.14that none of the estimated locations150,152,154are at the centroid170of the underground pipe13. Nor is the predicted location158at the centroid. It should be understood that field effects in large pipelines13often result in the detected position appearing “closer” to the sensor140A-C than it is. By using the estimated locations150,152,154to find an improved estimated location158, some of these known distortions can be avoided, though an artisan should be aware of potential errors.

The area defined by the triangle156from the three separate measurements of located position (150,152,154), is an indicator of the magnitude of error of the current location position. As the set of three sensors140A-C are moved across the pipeline13, the position and area of the location triangle156changes for each position measurement of the pipeline13. The centroid158of the triangle156would be used to indicate the best estimate of pipeline13centroid location for any position of the frame103(FIG.10). The smallest location triangle156area will indicate the most accurate location.

In some cases, the area of the location triangle156can be used to indicate an acceptable location determination, or in other words, if the area is too large, then location uncertainty is too great to accept. The detection can thus be halted for a secondary locate operation, such as soft excavation, or the process repeated to see if an acceptable error value can be achieved.

Another advantage of the method of using three antenna sets instead of just one or two, is that if any single locator140A-C is faulty, it will produce a location triangle158that is oddly shaped. The processor100can discern by analyzing the results and giving a stop signal in the location operation. Note that this technique might be extended to more than three antennas if higher accuracy or improved reliability is required.

Four potential options for sensors that would sense unintended encroachment of the pipeline13are given below. These options may be described as acoustic, capacitive, inductive, and reflected impedance. The term “encroachment” is used to define separation between the pipeline13and a plow assembly30or other blade.

Accurate distance measurement requires knowledge of pipeline geometry, pipeline material and, usually, material properties of the soil matrix. Soil matrix material properties are rarely known in detail. As a result, techniques for location are qualitative indications of separation rather than reasonably accurate quantitative separation measurements. For example, differential transit time acoustic measurement, described in the following paragraphs, is expected to provide reasonable indication of encroachment, but calculation of separation distance requires knowledge of signal propagation velocity in the soil. Determination of soil velocity is difficult and disturbed soil, often associated with fill placed above and about a pipeline, is typically nonhomogeneous.

Acoustic Sensing

Acoustic approach detection is similar to seismic technology employed in geophysics and the petroleum industry, in ranging applications such as RADAR and SONAR, and in ultrasound studies. The word “acoustic” is used here in the general sense of propagating compression and rarefaction wavefronts in a medium, whether or not it creates sound audible to the human ear.

Acoustic ranging may use a single transducer as both transmitter and receiver, but design complications of the single-transducer approach can be avoided using separate transmitting200and receiving202elements. This separate-element geometry is well suited to underground applications, where typical plow blade and tool housing geometries allow use of separated transmitter and receiver elements. This, in turn, permits optimization of each element for its particular purpose.

An acoustic impulse may be coupled to the trench or borehole wall by a variety of methods. An air gap between source and the soil matrix wall may be avoided using a variety of spring-loaded or other mechanically coupled design options. The general geometry of the problem is shown inFIG.8, which illustrates a single acoustic source200and two acoustic receivers202. A stimulus signal from the source200propagates through the medium (soil, in this case) and, if a defined surface is present (e.g., a pipeline13), a portion of the acoustic energy is reflected and propagates back to the receiving elements202on the plow blade32or installation machine10. The transit time between stimulus and reflected signal reception is a function of the path length and the velocity of the medium, as noted inFIG.8.

Drilling and plowing operations are done in the top surface (vadose zone) of the soil column, where propagation velocities vary tremendously even in intact material. Transit time is sufficient to determine an undesired approach to a pipeline, even if it is not possible to calculate the separation distance with reasonable accuracy (the calculation requires knowledge of the medium's propagation velocity). If a reflection is detected, it is clear evidence a reflecting surface is present. If the reflection transit time decreases as drilling or plowing continues, it is evidence the plow blade32or installation machine10is approaching the pipeline.

FIG.8illustrates an arrangement whereby multiple (in this case, two) sensors202are employed, each having a different offset distance from the source element200. In this arrangement, it is possible to measure a differential transit (or arrival) time, Δt—the time difference between reflected wavefront arrivals from the same source pulse as measured by sensors having different offsets. We assume the sensor with offset d1is closest the leading edge of the plow blade32or the head of the drilling tool. If separation h is large compared to d1and d2, the differential arrival time Δt is approximately zero. As separation h decreases, the differential arrival time Δt begins to increase, as shown in the simulation ofFIG.9. An increased differential arrival suggests the shorter offset d1relative to the separation distance h is becoming a significant consideration. This, in turn, suggests the blade32or bit is very near the pipeline13. The differential arrival time is monotonic with increasing slope as separation distance decreases.

Assuming that the signal is transmitted at time t=0, the following relationship can be used to calculate the distance h from the pipe (as shown inFIG.8) using known and sensed values. Velocity of the signal through the medium is the unknown v, but assumed to be uniform.

t1=1v⁡[2⁢h2+(12⁢d1)2]=1v⁡[4⁢h2+d12]t2=1v⁡[2⁢h2+(12⁢d2)2]=1v⁡[4⁢h2+d22]
With a differential arrival of the signals back at receivers202at Δt:

Δ⁢t=1v⁡[4⁢h2+d22-4⁢h2+d12]
Velocity is unknown, but if it assumed to be locally uniform along the path of each signal, the differences between the times of signal arrival and the known distances between the source200and receivers202can be used to determine how distance h is changing:
Δt∝√{square root over (4h2+d22)}−√{square root over (4h2+d12)}
Capacitive Sensing

Most large pipelines13are metal. A sensor may use detection technology responsive to the capacitance between an isolated metal plate on the plow blade or drill housing and the pipeline being paralleled. In this approach, the soil matrix is a nonhomogeneous lossy dielectric, which makes the response very difficult to predict analytically. It is anticipated a capacitive response will be a near-field effect useful when capacitance begins to shift as a function of distance traveled. Accurate frequency measurements are readily implemented by electronics suitable for subsurface applications, making use of sensed capacitance to vary, or “pull,” the frequency of an oscillator in the plow blade or tool a preferred technology. Isolation of the tool- or blade-mounted capacitor plate may be achieved by embedding a metal plate in an insulating window made of ceramic, polyurethane, or other suitable material.

Metal pipelines13with reasonable conductivity are readily located by inductive methods typical of those used by metal detectors and a locating receiver's “broadcast mode.” The instrument generates a source electromagnetic field which induces eddy currents in the metal object or pipeline. These eddy currents produce an electromagnetic field which is detectable by suitable receiver electronics. Pipelines13comprise a significant mass of metal and have generally linear structures, making metal detection technology a very reasonable technical option to avoid encroachment while paralleling a pipeline.

A source coil is needed to generate the exciting electromagnetic field. In the case of a plow (or trencher) blade, the source may be implemented by a coil embedded in a structural pocket in the plow blade itself. An especially desirable way to form the mounting pocket is by assembling the plow blade from a plurality of nonmagnetic metal sheets (e.g., Nitronic 50, Nitronic 60, Magnalloy, or Monel) bolted or otherwise joined together to form a laminar composite structure. Interior layers may contain voids and channels to create the pocket needed to accommodate a source induction coil and associated electrical wires. Alternatively, the exterior layers may be fabricated with voids or windows immediately adjacent the source induction coil.

These exterior voids or windows will be formed using ceramic plate, polyurethane, or other suitable nonmagnetic, non-conductive material with mechanical properties suitable for use in the underground construction environment. A generally cylindrical tool housing may be fabricated in a similar fashion using non-magnetic alloys and a non-magnetic, non-conductive window.

A pulsed source will induce eddy currents in the pipeline metal. When the source signal is turned off with sufficient rapidity, the eddy currents will decrease over time in a characteristically exponentially-decaying pattern readily detected and processed by a receiving antenna and associated electronics in the plow blade or tool housing. This technique is known in the art as the Transient Electromagnetic (TEM) method, time-domain electromagnetic (TDEM) method, or pulse electromagnetic (PEM) method. There are advantages to using different antennas for the source signal and to detect the received signal, but this is not a design requirement.

Transformer Reflected Impedance

Electrical power transformer designers are familiar with reflected impedance, a phenomenon describing the effect a load (or load change) on one transformer winding produces on the other winding(s). A simple single-primary, single-secondary transformer may be used. The source excitation signal is applied to the primary, and the secondary circuit's load impedance is called simply the load. While the impedance of either winding can be reflected to the other winding, this discussion concerns the secondary winding's reflected load effect on the primary winding. We remind the reader transformers are AC devices.

The load on the secondary winding is a complex impedance. The impedance has a resistive portion and a reactive portion. The reactive portion of the load may be either capacitive or inductive and, in the case of power transformers, the effect of load impedance is associated with a measurement called the power factor, a measure related to the cosine of the phase relationship between the transformer's primary voltage and primary current. Load impedance variations produce corresponding changes in the phase relationship between voltage and current in the transformer primary.

Whereas power engineers often wish to minimize reflected impedance effects and reduce power losses in the transformer, this embodiment deliberately emphasizes or enhances the transformer's sensitivity to reflected impedance (whether capacitive or inductive) to detect the approach of the installation machine10to a pipeline13. The sensing device(s) on the transformer's secondary may be either a coil, a conductive plate, or both. Because the reflected impedance technique will work with either inductive or capacitive load variations, it is amenable to whichever effect (inductive or capacitive) is dominant. The transformer's secondary may also have a resistive load component to manipulate the transformer's secondary load impedance for greatest sensitivity to the reactive reflected signal component in the primary winding. The actual measurement itself will be the phase difference between the primary voltage and primary current waveforms.

Changes may be made in the construction, operation and arrangement of the various parts, elements, steps and procedures described herein without departing from the spirit and scope of the invention as described herein and in the claims.