WO2019241849A1

WO2019241849A1 - Apparatus and process for assessing coating damage and cathodic protection of buried pipelines

Info

Publication number: WO2019241849A1
Application number: PCT/AU2019/050641
Authority: WO
Inventors: Ying HUO; Yongjun Tan
Original assignee: Energy Pipelines CRC Ltd.
Priority date: 2018-06-21
Filing date: 2019-06-21
Publication date: 2019-12-26

Abstract

A buried pipeline assessment process, including the steps of: traversing a sensor along a path parallel and proximal to at least a portion of a buried pipeline having damaged regions where a protective coating was damaged during introduction of the pipeline into a bore created by horizontal-directional drilling (HDD); during traversal of the sensor along the path, using the sensor to detect deviations in local polarisation, wherein a deviation in the local polarisation at a corresponding location along the path is indicative of a corresponding damaged region of the protective coating at a corresponding location along the buried pipeline where metal of the buried pipeline is exposed; responsive to each said detection, using the sensor to measure electrochemical impedance at the corresponding location along the path, wherein the measured electrochemical impedance is indicative of a size of a corresponding region of exposed metal of the pipeline at the corresponding location along the buried pipeline; and processing sensor data representing the measured electrochemical impedance at each said location to generate pipeline damage data representing the locations and sizes of the regions of exposed metal along the buried pipeline.

Description

APPARATUS AND PROCESS FOR ASSESSING COATING DAMAGE AND CATHODIC PROTECTION OF BURIED PIPELINES

TECHNICAL FIELD

The present invention relates to a buried pipeline assessment apparatus and process for locating and quantifying damage to the protective coatings on buried horizontal-directional drilling (HDD) pipelines, and for monitoring the effectiveness of cathodic protection of damaged buried pipelines.

BACKGROUND

Horizontal directional drilling (HDD) is a trenchless method of installing underground pipelines in locations where trenching or excavation is infeasible or undesirable. Examples of such locations include areas containing rivers, shore-lines, railway lines, road and creek crossings, as well as sensitive wildlife habitats and the like. Since its initial use in Australia in the early 1990s, the use of HDD has increased dramatically, and HDD is now a widely used method of energy pipeline installation.

Although HDD brings major benefits to the pipeline industry, the installation of pipelines within bores created by HDD is a complex operation that can cause significant damage to the protective coatings on the pipelines, including through-thickness scratching and cracking, for example. Although abrasion resistant coatings have been applied to reduce coating damage during pipeline installation, significant coating damage still occurs due to the large and complex bending stresses caused by the bending of pipelines as they are fed into and through bores, and the abrasion forces experienced by the coatings during this process.

It is usually impractical to repair a damaged HDD pipeline coating, and consequently it is critical to determine the locations of defects in the coatings, in particular missing regions of the coatings (referred to in the art as "holidays") where metal of the pipeline is exposed and is thus vulnerable to corrosion, and to ensure that cathodic protection (CP) is effective in protecting HDD pipes with damaged coatings. However, there is currently no technology available to the pipeline industry to determine the location of holidays in HDD pipelines. Moreover, even if the locations of holidays was known, there are a number of circumstances in which HDD installed pipelines cannot be effectively protected by conventional CP systems, and the efficiency of CP of HDD pipelines is generally unknown. For example, there is insufficient data to verify the performance of standard testing methods such as the Direct Current Voltage Gradient (DCVG) technique, the on-potential swing test method, or the polarisation change method in assessing coating defects on HDD pipes.

It is desired, therefore, to provide a buried pipeline assessment apparatus and process that alleviate one or more difficulties of the prior art, or to at least provide a useful alternative.

SUMMARY

In accordance with some embodiments of the present invention, there is provided a pipeline assessment process, including the steps of:

traversing a sensor along a path parallel and proximal to at least a portion of a buried pipeline having damaged regions where a protective coating was damaged during introduction of the pipeline into a bore created by horizontal-directional drilling (HDD); during traversal of the sensor along the path, using the sensor to detect deviations in local polarisation, wherein a deviation in the local polarisation at a corresponding location along the path is indicative of a corresponding damaged region of the protective coating at a corresponding location along the buried pipeline where metal of the buried pipeline is exposed ;

responsive to each said detection, using the sensor to measure electrochemical impedance at the corresponding location along the path, wherein the measured electrochemical impedance is indicative of a size of a corresponding region of exposed metal of the pipeline at the corresponding location along the buried pipeline; and

processing sensor data representing the measured electrochemical impedance at each said location to generate pipeline damage data representing the locations and sizes

of the reg ions of exposed metal along the buried pipeline.

In some embodiments, the path traversed by the sensor is within a second bore that is separate to and spaced from the bore conta ining the buried pipeline. In other embodiments, the path traversed by the sensor is within the bore containing the buried pipeline. In some embod iments, the process includes the step of introducing the pipeline into the bore, together with a traversal cable for pulling the sensor along the buried pipeline. In some embod iments, the process includes the step of creating the bore containing the buried pipeline by horizontal-directional drilling (HDD) .

In some embodiments, the process includes the step of providing cathodic protection at surface locations corresponding to at least some of said locations along the buried pipeline to red uce corrosion of the corresponding exposed metal regions of the pipeline.

In some embodiments, the process includes the step of traversing a sensor along the path to the at least some of said locations a long the buried pipeline, and at each of those locations using the sensor to assess the effectiveness of the provided cathodic protection .

In accordance with some embodiments of the present invention, there is provided at least one computer-reada ble storage medium having stored therein processor-executable instructions that, when executed by at least one processor, cause the at least one processor to execute the buried pipeline assessment process of a ny one of the a bove processes.

In accordance with some embodiments of the present invention, there is provided a buried pipeline assessment a ppa ratus having components configured to execute the buried pipeline assessment process of any one of the a bove processes.

In accordance with some embodiments of the present invention, there is provided a buried pipeline assessment apparatus, including :

a sensor component configured to measure local polarisation at each of a plurality of locations along a path parallel and proximal to at least a portion of a buried pipeline, and to measure electrochemical impedance at selected ones of the locations; and

at least one processor in communication with the sensor component, and configured to:

generate signals to control the traversal of the sensor component along the path;

receive from the sensor component, for each of the plurality of locations along the path, local polarisation data representing a measurement of local polarisation at the location;

process the received local polarisation data to detect whether a protective coating of the pipeline at a corresponding location along the pipeline has been damaged such that metal of the buried pipeline is exposed at the corresponding location along the pipeline;

responsive to detection of exposed metal of the buried pipeline at the location, to:

(i) send a signal to the sensor to cause the sensor to measure electrochemical impedance at the location;

(ii) receive from the sensor electrochemical impedance data representing a measurement of electrochemical impedance at the location; and

(iii) process the received electrochemical impedance data to generate corresponding coating defect data representing a size of at least one region of exposed metal of the buried pipeline at the location; and

generate pipeline damage data representing the locations and sizes of regions of exposed metal along the buried pipeline.

In some embod iments, the at least one processor is further configured to :

generate signals to control the traversa l of the sensor component along the path parallel and proxima l to the buried pipeline to successively position the sensor component at each of a plurality of assessment locations, being a subset or a ll of the locations at which damage to the buried pipeline was detected ; a nd

for each said assessment location, receive from the sensor component corresponding cathodic protection data representing a corresponding measurement of potential at the corresponding assessment location ; and

process the received cathodic protection data to generate cathodic protection data indicative of cathodic protection effectiveness at each of the assessment locations.

In some embodiments, the path traversed by the sensor is within a second bore that is separate to a nd spaced from the bore conta ining the buried pipeline.

In some embodiments, the path traversed by the sensor is withi n the bore containing the buried pipeline.

Also described herein is a pipeline assessment process, including the steps of:

traversing a sensor along a bore created by horizonta l-directional d rilling (HDD) a nd containing a buried pipeline having damaged regions where a protective coating was damaged during introduction of the pipeline into the bore;

d uring traversa l of the sensor along the pipeline, using the sensor to detect deviations in loca l polarisation, wherein a deviation in the local polarisation at a corresponding location along the pipeline is indicative of a corresponding damaged region of the protective coating at sa id location;

responsive to each said detection, using the sensor to measure electrochemical impedance at the corresponding location along the pipeline, wherein the measured electrochemical impedance is indicative of a size of the damaged region of the protective coating of the pipeline at said location; and

processing sensor data representing the measured electrochemical impedance at each sa id location to generate pipeline damage data representing the locations and sizes of the da maged regions a long the buried pipeline.

Also described herein is a pipeline assessment system, including : a sensor component configured to measure local polarisation at each of a plurality of locations along a bore conta ining a buried pipeline, the plurality of locations being adjacent to the buried pipeline, a nd to measure electrochemical impedance at selected ones of the locations; and

at least one processor in communication with the sensor component, a nd config ured to :

generate sig nals to control the traversal of the sensor component along the bore containing the buried pipeline;

receive from the sensor component, for each of the plurality of locations a long the buried pipeline, local pola risation data representing a measurement of loca l polarisation at the location ;

process the received local polarisation data to detect whether a protective coating of the pipeline at the location has been damaged ;

responsive to detection of damage to the protective coating at the location, to :

(i) send a signal to the sensor to ca use the sensor to measure electrochemica l impedance at the location;

(ii) receive from the sensor electrochemical impedance data representing a measurement of electrochemical impedance at the location ; and

(iii) process the received electrochemica l impedance data to generate corresponding coating defect data representing a size of at least one damaged region of the protective coating at the location ; and

generate pipeline da mage data representing the locations and sizes of damaged regions of the protective coating along the buried pipeline.

The at least one processor may be further configured to :

generate signals to control the traversal of the sensor component along the bore containing the buried pipeline to successively position the sensor component at each of a plurality of assessment locations, being a subset or all of the locations along the buried pipeline at which damage was detected; and

for each said assessment location, receive from the sensor component corresponding cathodic protection data representing a corresponding measurement of potential at the corresponding assessment location; and

BRIEF DESCRIPTION OF THE DRAWINGS

Some embodiments of the present invention are hereinafter described, by way of example only, with reference to the accompanying drawings, wherein :

Figure 1 is a schematic cross-sectional side view of a buried pipeline being installed by using a horizontal drilling rig to pull the pipeline through a generally horizontal bore hole created by Horizontal Directional Drilling (HDD) under an obstacle (e.g. , a body of water), including an inset showing a magnified view of the attachment between a drilling reamer and the pipeline;

Figure 2 includes a schematic cross-sectional side view of pipeline being pulled through the bore, showing obstacles (e.g., sharp rocks as shown in the accompanying photograph) projecting into the bore and damaging the protective coating of the pipeline;

Figures 3 and 4 are photographic images of two different pipelines with damaged protective coatings;

Figure 5 is a flow diagram of a buried pipeline assessment process in accordance with some embodiments of the present invention;

Figure 6 is a block diagram of a buried pipeline assessment apparatus in accordance with some embodiments of the present invention;

Figure 7 is a schematic cross-sectional side view of a buried pipeline being assessed by pulling a sensor adjacent to the pipeline through the HDD bore hole;

Figure 8 is a schematic cross-sectional side view of a first embodiment of a sensor, in the form of a sinker with embedded electrodes;

Figure 9 includes CAD images of a second embodiment of a sensor, in the form of electrodes embedded in an armoured cable;

Figure 10 includes photographic images of a third embodiment of a sensor, in the form of electrodes embedded in an armoured cable;

Figure 11 includes computer-generated cross-sectional side views of the third embodiment of a sensor, showing the electrode configurations and electrical connections;

Figure 12 is a graph of local polarisation measurements as a function of location along a buried pipeline, showing a local minimum current or 'dip' feature indicative of a defect in the protective coating of the pipeline;

Figure 13 is a graph of capacitances calculated from electrochemical impedance measurements as a function of location along the buried pipeline of Figure 12, showing a local maximum capacitance or 'peak' feature indicative of and quantifying the size of the defect in the protective coating of the pipeline;

Figure 14 is a graph illustrating the linear relationship between the sizes (areal dimensions in cm²) of defects in the protective coating of the pipeline and the capacitance measured by electrochemical impedance spectroscopy at the locations of those defects;

Figure 15 is a schematic cross-sectional side view of a buried pipeline and sensor adjacent to the pipeline being pulled through the HDD bore hole to assess the effectiveness of cathodic protection (CP) of the pipeline at locations of defects in the protective coating of the pipeline; and

Figure 16 is a schematic cross-sectional view of a section of a buried pipeline and an adjacent and parallel borehole containing a slotted conduit along which the probe or sensor assembly is moved and used to assess corresponding locations of the buried pipeline.

DETAILED DESCRIPTION

In order to address difficulties of the prior art, embodiments of the present invention include a buried pipeline assessment apparatus and process, as shown in Figures 5 and 6, that can efficiently determine the locations and sizes (in terms of pipeline surface area) of regions of metal exposed at holidays in the protective coatings of buried pipelines. This information can then be used to determine the locations at which to install cathodic protection (CP) components, and the amount of cathodic protection required at each location (based on the size of the corresponding holidays). Additionally, the pipeline assessment apparatus and process described herein can be used to determine the effectiveness of cathodic protection at each holiday location along the buried pipeline.

As shown in Figure 6, the buried pipeline assessment apparatus includes a probe or sensor assembly 602, a controller 604, a sensor interface 606, and sensor position controllers 608, 610. The sensor interface 606 is a potentiostat/galvanostat that is able to perform each measurement described herein via direct electrical connections with the electrodes of the sensor assembly 602 and under control of the controller 604 via network interfaces of the controller 604 and the sensor interface 606. In the described embodiments, the sensor interface 606 is a BioLogic SP-200 potentiostat/galvanostat, available from Bio-Logic Science Instruments, and described at http://www.bio- ioqic.net/en/products/muitich3nnei-conductiv8ty/sp-200-potentiostat-qaivanostat. In the described embodiments, the controller 604 is an off-the-shelf computer such as an Intel Architecture 64-bit computer, and the buried pipeline assessment process is implemented as executable instructions of one or more software modules 612 stored on non-volatile storage 613 of the computer. However, in other embodiments, the buried pipeline assessment process may be implemented, either in part or in its entirety, as configuration data for a field-programmable gate array (FPGA) and/or as one or more dedicated hardware components such as an application-specific integrated circuit (ASIC), for example.

The controller 604 includes random access memory (RAM) 614, at least one processor 616, and external interfaces 618, 620, 622, all interconnected by a bus 624. The external interfaces include universal serial bus (USB) interfaces 618, at least one of which is connected to a keyboard 626 and a pointing device such as a mouse 628, a network interface connector (NIC) 620 which connects the apparatus 604 to a communications

network such as the Internet 630, and a display adapter 632, which is connected to a display device such as an LCD panel display 634.

The controller 604 may also include a number of standard software modules 636 to 330, including an operating system 636 such as Linux or Microsoft Windows, web server software 638 such as Apache, available at http://www.apache.org, scripting language support 640 such as PHP, available at http://www.php.net, or Microsoft ASP, and structured query language (SQL) support 642 such as MySQL, available from http://www.mysql.com, which allows data to be stored in and retrieved from an SQL database 644.

Together, the web server 638, scripting language module 640, and SQL module 642 provide the system 300 with the general ability to allow users of the apparatus with standard computing devices equipped with standard web browser software to access the apparatus and in particular to receive pipeline assessment data from the database 644.

However, it will be understood by those skilled in the art that the specific functionality provided by the system 300 to such users is also provided in part by scripts accessible by the web server 638, including the one or more software modules 612 implementing the process 500, and also any other supporting scripts and data 646, including markup language (e.g ., HTML, XML) scripts, PHP (or ASP), and/or CGI scripts, image files, style sheets, and the like.

As shown in Figure 5, the buried pipeline assessment process begins at step 502 by using horizontal-directional drilling (HDD) to form a buried pipeline, such as an energy pipeline, for example. As shown in Figure 1, this typically involves using an HDD drill rig 102 to form a generally horizontally directed and buried cylindrical borehole 104 with inclined sections leading to surface openings at the entry side 106 and exit side 108 of the borehole 104. When the drilling rig emerges from the ground at the exit side 108 of the bore, a pipeline or pipe string 110 is attached to the reamer 112 at the end of the drill pipe 114 and is then pulled into the borehole 104 by using the drilling rig 102 to withdraw the drill pipe 114 from the borehole.

The pipeline or pipe string 110 is typically in the form of an elongate hollow cylinder formed of steel with a protective outer coating to protect the steel pipe from corrosion. However, as described above, the extreme stresses applied to the coating as the pipe 110 is pulled through the borehole 104 inevitably causes damage to the pipe 110, in particular by removing regions of the protective coating at various locations along the length of the buried pipe 110. For example, Figure 2 includes a schematic cross-sectional side view showing opposed projections 116 extending into the borehole 104 and damaging the pipeline 110 as it is pulled through the borehole 104 towards the drilling entry side 106. Typically, these projections are rocks, as shown in the accompanying photographic image, which often have sharp projections that scratch or remove the protective coating of the pipeline as it is pulled past those projections. Figures 3 and 4 are photographic images showing examples of different types of pipelines 110 damaged during installation into HDD boreholes 104. It will be apparent that this damage, in particular where the underlying bare metal is exposed by removing portions of the protective coatings, makes the pipelines 110 vulnerable to corrosion.

However, in accordance with some embodiments of the pipeline assessment process and apparatus described herein, the probe or sensor assembly 602 is also pulled into the HDD borehole 104 along with the pipeline 110. The probe or sensor assembly 602 includes sensor electrodes (including a counter electrode and a reference electrode) exposed at the surface of a sensor body that is attached to electrical and structural cables. The electrical cables convey electrical signals to and from the sensor electrodes, and the structural cable allows the sensor body to be pulled through the borehole in either direction so that the sensor electrodes can be used to evaluate the condition of the buried pipeline 110 at any desired location along its length. In some embodiments, as shown in Figure 8, the sensor body 802 has a bullet-like shape with a rounded and hardened forward head 804 to facilitate traversal through the borehole 104, and a truncated rear surface 806 in which the reference electrode (RE) 808 and counter electrode (CE) 810 are exposed, as shown in Figure 8. The structural 812 cable extends from the sensor body 802 in forward and rearwards directions to the respective cable positioners 608, 610, and the electrical cable 814 carrying the electrode signals extends from the rear surface 806 of the sensor body 802 to the sensor interface 606.

In some embodiments, as shown in Figures 9 to 11, the sensor assembly is in the form of a steel wire armoured cable 1102 containing the respective electrical cables 1104, 1106 for the reference electrode 1108 and the counter electrode 1110, as shown in Figure 11, and each of the electrodes 1108, 1110 is in the form of a short length of platinum wire, of which a portion (of 1 cm length in the described embodiment) is exposed at the surface of the armoured cable 1102.

In the embodiment of Figure 9, the two platinum wire electrodes 902, 904 protrude from openings in the surface of a stainless steel cylinder 906 that protects the electrodes 902, 904 and is electrically insulated from them, and an annular moat 908 of epoxy protects the protruding electrodes 902, 904 from damage as the sensor assembly 900 is moved along the borehole 104.

In the embodiment of Figure 10, the steel wire armoured cable 1002 includes a protective outer sheath 1004, of which a short length is removed at the location 1006 of the platinum wire electrodes 1108 so that the electrodes 1108 are effectively shielded by being positioned slightly within the outer diameter of the protective sheath 1004.

Returning to the flow diagram of Figure 5, once the sensor assembly has been installed in the borehole and is adjacent to the pipeline 110 to be assessed, the sensor assembly can be used to assess the installed buried pipeline 110. At step 504, the sensor assembly is moved so that the sensor electrodes are positioned at a desired location of the buried pipeline 110. If this is the first assessment of an installed pipeline 110, then this location would typically be at either end of the buried portion of the pipeline 110. Although the positioning of the electrodes can be performed manually, for example by manually controlling a winch or similar winding mechanism to roll one end of the sensor assembly cable onto a cable drum at either the entry side or exit side of the borehole (depending on which direction the sensor electrodes need to be moved in order to position them at the desired location), in the described embodiments this is achieved by using the controller 604 to control the roller motors/actuators 608, 610 in order to position the sensor electrodes.

When the sensor electrodes have been moved to the desired location along the buried pipeline at step 504, at step 506 the controller 604 instructs the sensor interface 606 to

make a measurement of local cathode polarisation using the positioned sensor electrodes. The measurement involves applying a local cathodic polarisation potential to the pipe. In the described embodiments, the reference electrode is a Cu/SuSC>4 reference electrode (referred to in the art by the abbreviation "CSE") and the applied potential is -1.2V vs CSE. However, in other embodiments the reference electrode can be any suitable reference electrode, including commercially available reference electrodes known to those skilled in the art (including platinum wire), provided that they have stable potentials. The sensor electrodes then measure the resulting local polarisation currents in order to reveal the presence of coating holidays at the measurement location, as described in further detail below. The time taken to make each of these local current measurements is relatively short, being only about 3 to 4 seconds, and therefore the locations of holidays along a pipe can be determined relatively quickly.

Once a local polarisation measurement has been made, it is communicated to the controller 604 at step 508 so that the controller can process the measurement to determine whether the measurement is indicative of the presence of one or more regions of metal exposed at holidays in the protective coating of the pipeline 110 at the measurement location.

For example, Figure 12 is a graph showing the measured electrical current (in mA) as a function of distance (in cm) along a length of damaged pipe for an applied voltage of -1.2V vs CSE. The substantial local current minimum (dip or trough) in the polarisation current (in this example being from a level of about -0.5mA down to nearly -3mA in the pipeline region between about 150 and 200 cm) is indicative of the presence of one or more regions of exposed pipeline metal in that part of the pipeline.

If the assessment performed at step 508 determines that the measurement of polarisation is not indicative of a region of exposed metal at the current measurement location along the pipeline, then the process branches to step 510 to determine whether there are more locations along the pipeline to be assessed. For example, in one operation mode, the pipeline assessment process assesses evenly spaced locations along the entire buried length of the pipeline 110. In this case, the next location to be assessed is a predetermined spacing distance away from the location that has just been assessed. In another operating mode, a list of predefined (and arbitrary) locations are to be assessed, in which case the

next location in the list is retrieved from memory of the controller 604. For example, a list of locations at which exposed metal regions have been identified by a comprehensive scan at closely spaced locations along a pipeline can be stored for use as the predetermined list of assessment locations for subsequent assessments at later dates in order to further improve the efficiency of the later assessments.

In either case, provided that there are more pipeline locations to be assessed, the process branches back to step 504, and the sensor assembly cable is wound onto the corresponding roll and by a corresponding amount in order to position the sensor electrodes at the next assessment location determined at step 510.

Returning to step 508, if the controller determines that the local polarisation measurement is indicative of regions of pipeline metal exposed at holidays in the protective coating of the pipeline at the measurement location, then at step 512, the controller sends an instruction to the sensor interface to perform an Electrochemical Impedance Spectroscopy (EIS) measurement at the current location. This involves applying to the pipe (as the working electrode) a small amplitude (e.g., ±20mV) sinusoidal AC signal over a wide range of frequencies, as described below. The frequency dependent response provides information on electrolytes (at high frequencies), charge transference controlled reactions (at low frequencies) and diffusion controlled reactions (at very low frequencies). Typically, the working electrode (pipe) is polarised around the Open Circuit Potential (OCP) as a DC offset to which the AC signal is applied . For example, Figure 15 shows an electrochemical test apparatus that was used to carry out EIS measurements on epoxy coated pipeline steel electrodes with defects. EIS tests can be ca rried out at OCP (before the pipe is tied-in), or under applied CP potential/current (after the pipe has been tied-in) conditions.

In the described embodiments, a sinusoidal potential signal with an amplitude of 10 mV is applied at OCP. The impedance response is measured over frequencies between 105 Hz to 10^-2 Hz, recording 10 points per decade of frequency.

The most important step of the EIS measurement is the extraction of useful information from EIS diagrams, as described in Mansfeld, F. ( 1995), Use of electrochemical impedance spectroscopy For the study of corrosion protection by polymer coatings, in Journal of Applied

Electrochemistry, 25, 187 ("Mansfeld"). This EIS analysis is used to determine the various parameters shown in Figure 18 of Mansfeld, i.e., coating capacitance (C_c), double layer capacitance (Cdi), polarisation resistance (R_P), pore resistance (R_po) and solution resistance (Rn). As described in Mansfeld, coatings can be categorised by measuring their impedance at a frequency of 100 mHz; specifically, an impedance of 1000 MW/cm² indicates an excellent barrier coating, an impedance in the range of 10 to 1000 MW/cm² indicates the presence of capillaries in the coating, while an impedance in the range from 0.1 to 10 MW/cm² suggests a coating with pinholes (see Mansfield and Kendig, M. W. Jeanjaquet, S. Lumdsden, J Scully J. R. Silverman D.C. and Kendig M.W. (eds.), Electrochemical impedance - Analysis and Interpretation, ASTM, Philadelphia, 1993 p407).

At step 514, the EIS measurement is used to estimate the size of the defect(s), this being an estimate of the total area (e.g., in cm²) of the bare metal surface of the pipeline exposed by removal of one or more regions of the protective coating at a position along the length of the pipeline corresponding to the measurement location of the sensor electrodes. Although the process of Figure 5 shows this conversion being performed after each EIS measurement, it will be apparent that the conversion of all EIS measurements could be performed together after all of the measurements have been performed .

For example, Figure 13 is a graph of the capacitance (in Farads) measured by EIS at each of a set of locations along the pipeline as a function of the distance of each of those locations from an arbitrary reference point, using the same distance scale as the graph in Figure 12. The EIS capacitance measurements show a clear and well-defined increase over the part of the pipeline from about 170 to 210 cm, corresponding to the dip or trough in the polarisation current shown in Figure 12, demonstrating that either method can be used to identify the locations of holidays in the protective coating of the pipeline.

However, in contrast to the polarisation measurements, the electrochemical impedance measurements can also be used to estimate the total aggregate size of the region or regions of exposed metal at each location along the pipeline. For example, Figure 14 is a graph showing the capacitance measured by EIS as a function of the sizes (in cm²) of artificially created holidays in the protective coating of a buried pipeline, demonstrating that there is a linear relationship between these two parameters, and consequently that, once calibrated

(by measuring a calibration curve in a pipeline of the same or similar environmental conditions), the holiday sizes can be determined or estimated from the EIS capacitance measurements. In the described embodiments, calibration curves are determined by inserting several coupons of different sizes into a borehole (either prior to or after insertion of the pipeline), and then performing measurements on those coupons in the borehole. This ensures that the same environmental conditions are used for the calibration measurements and the actual measurements along the pipeline. In practice, this is done by determining a line of best fit by standard regression through a corresponding calibration data set such as that shown in Figure 14, and the controller 604 uses the resulting formula to map each measured capacitance value received from the sensor interface 606 to a corresponding holiday size (area).

The EIS capacitance measurements are therefore more informative than the local polarisation measurements; however, EIS measurements suffer from a significant limitation that they are time-consuming to perform. For example, each EIS capacitance measurement takes around 3 to 4 minutes, making them impractical for use in detecting defects along the entire length of a buried pipeline. However, the buried pipeline assessment apparatus and process described herein overcome this difficulty by using a hybrid process whereby local polarisation measurements (each of which typically takes less than 10 seconds to perform) are used to detect whether each assessed location is defective, and, only when a location is detected as being defective, a substantially slower but more informative EIS measurement is taken to determine the size of the defective region(s) at that location. The described apparatus and process therefore combine the advantages of both methods and provide for the first time the ability to rapidly determine the locations and sizes of defects in HDD pipeline coatings.

In any case, the buried pipeline assessment process described above generates a data set representing the locations and sizes of holidays in the protective coating of the buried pipeline 110, determined in situ after installation of the pipeline in a borehole by HDD. The buried pipeline assessment apparatus can display the data set to a user of the apparatus via the local display and/or can send the data to a remote system via the communications network for further processing and/or display.

The generated data quantifies the extent of pipeline damage, and consequently the risk of pipeline corrosion. More importantly, it indicates the specific locations along the length of the buried pipeline that are vulnerable to corrosion, thereby facilitating the installation of cathodic protection measures at those specific locations.

For example, Figure 15 is a schematic cross-sectional side view illustrating a cathodic protection (CP) anode 1502 inserted into a vertical bore or tunnel 1504 drilled from the ground surface to a depth close to that of the HDD bore 1506. The vertical bore 1504 is drilled at a location corresponding to a location of exposed pipeline metal determined by the buried pipeline assessment process as described above so that the CP anode 1502 is in relatively close proximity to one or more exposed regions of the meta llic pipeline where the protective coating has been damaged or otherwise compromised . This form of cathodic protection per se is well known to those skilled in the art, and involves the application of a DC voltage to the anode to suppress electrochemical corrosion of the exposed pipeline metal. However, the effectiveness of its application as described herein is improved because the buried pipeline assessment apparatus and process described herein allow the CP anodes to be accurately placed at locations where they are needed most.

In addition to the above, the buried pipeline assessment apparatus and process can also be used to assess the effectiveness of cathodic protection at the location of each CP anode 1502 by positioning the sensor electrodes at the location of the corresponding pipeline holiday location, and monitoring the potential at that location. This can be done after any period of pipe service by pulling the sensor electrodes (as shown in Figure 15) through the HDD bore hole 1506 after the pipe is tied-in to the CP system 1508 and using the sensor electrodes to measure the local CP potential. This is used to ensure that a suitable level of CP is applied to HDD pipes with local coating holidays.

Finally, embodiments of the present invention have been described above in the context of the probe or sensor assembly 602 being installed in the bore containing the buried pipeline to be assessed, which generally requires the probe or sensor assembly 602 to be installed within the bore simultaneously with the pipeline itself. However, the inventors have determined that the probe or sensor assembly 602 can be installed within a separate bore that is parallel and proximal to (within 8 m of) the bore containing the buried pipeline. This

provides the advantage that the buried pipeline assessment apparatus and process can also be used to assess existing buried pipelines; that is, pipelines that have been installed without a probe or sensor assembly 602 being installed at the same time.

For example, Figure 16 is a schematic cross-sectional side view showing an existing buried pipeline 1602, parallel and proximal to which has been drilled a separate borehole 1604. In the described embodiments, the separate borehole 1604 has a diameter of about 80 mm and is spaced from the buried pipeline 1602 by a distance that is typically about 3 to 5 m, and is at most 8 m (with the sensitivity decreasing with increasing separation). For example, this borehole 1604 can be drilled parallel to the buried pipeline using either the PARATRACK steering tool available from VectorMagnetics (as described at https://www.vectormagnetics.com/paratrack-steering-tool/), or the RoGeo XYZ service from Rosen (as described at https ://www. rosen- aroup.com/globa i/sol utions/services/service/rogeo-xyz.htmi)·

After the borehole 1604 has been drilled, a conduit pipe (of about 50 mm diameter in the described embodiment) 1606 with spaced elongate openings or slits 1608 is installed into the borehole 1604, and is filled with a conductive fluid whose conductivity is selected to be similar with the conductivity of the surrounding soil. Methods for preparing such fluids are well known to those skilled in the art. In the described embodiments, the conductive fluid is a 'Max Bore HHD' drilling mud commercially available from RED HEAD, as described at http ://westcoastdrillingsupply.com/blog/2012/02/28/max-bore-hdd/. The probe or sensor assembly 602 is then pulled through the conduit and used to assess the buried pipeline 1602 in the same manner as described above.

Many modifications will be apparent to those skilled in the art without departing from the scope of the present invention.

Claims

CLAIMS:

1. A buried pipeline assessment process, including the steps of:

traversing a sensor along a path parallel and proximal to at least a portion of a buried pipeline having damaged regions where a protective coating was damaged during introduction of the pipeline into a bore created by horizontal- directional drilling (HDD);

during traversal of the sensor along the path, using the sensor to detect deviations in local polarisation, wherein a deviation in the local polarisation at a corresponding location along the path is indicative of a corresponding damaged region of the protective coating at a corresponding location along the buried pipeline where metal of the buried pipeline is exposed;

processing sensor data representing the measured electrochemical impedance at each said location to generate pipeline damage data representing the locations and sizes of the regions of exposed metal along the buried pipeline.

2. The process of claim 1, wherein the path traversed by the sensor is within a second bore that is separate to and spaced from the bore containing the buried pipeline.

3. The process of claim 1, wherein the path traversed by the sensor is within the bore containing the buried pipeline.

4. The process of claim 3, including introducing the pipeline into the bore, together with a traversal cable for pulling the sensor along the buried pipeline.

5. The process of any one of claims 1 to 4, including creating the bore containing the buried pipeline by horizontal-directional drilling (HDD).

6. The process of any one of claims 1 to 5, including providing cathodic protection at surface locations corresponding to at least some of said locations along the buried pipeline to reduce corrosion of the corresponding exposed metal regions of the pipeline.

7. The process of claim 6, including traversing a sensor along the path to the at least some of said locations along the buried pipeline, and at each of those locations using the sensor to assess the effectiveness of the provided cathodic protection.

8. A computer-readable storage medium having stored therein processor-executable instructions that, when executed by at least one processor, cause the at least one processor to execute the buried pipeline assessment process of any one of claims 1 to 7.

9. A buried pipeline assessment apparatus having components configured to execute the buried pipeline assessment process of any one of claims 1 to 7.

10. A buried pipeline assessment apparatus, including :

at least one processor in communication with the sensor component, and configured to :

responsive to detection of exposed metal of the buried pipeline at the

location, to :

(i) send a sig na l to the sensor to cause the sensor to measure electrochemical impeda nce at the location;

(iii) process the received electrochemica l impedance data to generate corresponding coating defect data representing a size of at least one region of exposed metal of the buried pipeline at the location ; and generate pipeline damage data representing the locations and sizes of regions of exposed meta l along the buried pipeline.

11. The a pparatus of claim 10, wherein the at least one processor is further configured to :

generate sig nals to control the traversal of the sensor component along the path parallel and proximal to the buried pipeline to successively position the sensor component at each of a plurality of assessment locations, being a subset or a ll of the locations at which damage to the buried pipeline was detected ; and

process the received cathod ic protection data to generate cathod ic protection data indicative of cathod ic protection effectiveness at each of the assessment locations.

12. The apparatus of claim 10 or 11, wherein the path traversed by the sensor is within a second bore that is separate to and spaced from the bore containing the buried pipeline.

13. The apparatus of claim 10 or 11, wherein the path traversed by the sensor is within the bore containing the buried pipeline.