Patent Description:
<NPL> discloses corrosion determination in small diameter pipes by radiography. <CIT> discloses detection of corrosion under insulation. <CIT> discloses an augmented virtual reality system.

Digital radiography is a form of X-ray imaging employing digital X-ray sensors in place of traditional photographic film. Digital radiography enables images to be captured and processed more rapidly without requiring chemical processing of the films used in traditional X-ray imaging. In addition, digital radiography enables the digitally captured X-ray data to be efficiently transferred and enhanced as digital images. In this way, digital radiography provides immediate availability of the X-ray data and can allow for special image processing techniques to be applied in a variety of practical applications, such as corrosion and/or erosion monitoring in insulated pipes.

Determining corrosion and/or erosion under insulation (CUI) is important in many industrial domains to maintain safe and efficient transport of products within insulated pipes configured to transport the product. Corrosion and/or erosion can occur at many places along the interior surface of a pipe and can be difficult to inspect when pipes are covered in an insulated material or other similar form of insulation. Corrosion is an electro-chemical process resulting in deterioration of the pipe material and the production of rust on the pipe, thereby making the corrosion self-evident. Erosion is a mechanical process that results in deterioration of the pipe material by physically moving pipe material from one location to another. Traditional methods of pipe inspection and corrosion and/or erosion monitoring, such as ultrasonic techniques, require removal of the insulation prior to inspection due to the poor attenuation characteristics of ultrasonic energy penetrating the pipe insulation and the pipe wall. Insulation removal can increase the cost and logistical complexity of corrosion and/or erosion inspections as well as routine maintenance activities and can thereby by increase the overall operating costs of the pipeline in which the insulated, corroded pipes are configured.

Efficiently inspecting insulated pipes for CUI can be desirable for pipe owner/operators as corrosion and/or erosion may be present in one location of pipe but not in another. The ability to assess an amount of corrosion and/or erosion, such as an amount of material that has been corroded away from an inner surface of a pipe wall at a particular location, can be a requirement when performing inspections. Some traditional corrosion and erosion monitoring and/or inspection systems only provide inspection capabilities at a single location and require the inspection system to be repeatedly re-deployed and reconfigured at multiple locations so that a comprehensive assessment of corrosion and/or erosion can be generated for an entire length of insulated pipe. While monitoring and inspection systems may be removed from a pipe and re-installed periodically, such as when transitioning to a new section of pipe, and/or when a path along a pipe is blocked by a supporting member or the like, ideally, an improved corrosion monitoring system would enable inspections could be conducted in a linear fashion along the length of an insulated pipe without having to remove and reconfigure the inspection system/apparatus.

As described herein, an improved corrosion and erosion monitoring system can be configured to inspect an insulated pipe or portions of pipe to determine an amount of material loss occurring at one or more locations along the length of the pipe. The improved corrosion and erosion monitoring system uses digital radiography to effectively distinguish pipe insulation from the pipe wall in order to accurately determine locations of the pipe where material has been lost to erosion or corrosion. The improved corrosion and erosion monitoring system can travel along the length of an insulated pipe and perform inspections at multiple locations without requiring inspection personnel to remove and reposition the system from the insulated pipe. In this way, pipeline operators can deploy the improved corrosion and erosion monitoring system onto an insulated pipe at a first location to calibrate the system and can navigate the inspection system to a second location without having to physically remove the inspection system from the pipe and without having to remove the insulation from the pipe in order to perform an inspection of the pipe for corrosion and/or erosion. As a result, maintenance and repair costs can be decreased compared to traditional systems and methods used for corrosion and/or erosion monitoring and inspection.

<FIG> is a system diagram illustrating a corrosion and erosion monitoring system <NUM> configured to determine an amount of wall loss within an insulated pipe or on the outside of the pipe without requiring the insulation to be removed. As shown in <FIG>, the corrosion and erosion monitoring system <NUM> is configured in relation to a portion of a pipe <NUM>. The pipe <NUM> is covered by a layer of insulation <NUM> to form an insulated pipe. The insulated pipe can include one or more couplings, joints, fittings, valves, or other mechanisms used to link or couple one or more sections of pipe together. The pipe <NUM> can include a range of outer diameters between <NUM>" and <NUM>", for example in some embodiments, the outer diameter of the pipe can be <NUM>-<NUM>", <NUM>-<NUM>", <NUM>"-<NUM>", <NUM>"-<NUM>", and/or <NUM>-<NUM>". The pipe <NUM> can include a variety of inner diameters that may be appropriately sized depending on the outer diameter of the pipe <NUM>, the product being conveyed within the pipe <NUM>, as well as the industrial application in which the pipe <NUM> is configured to operate. The pipe <NUM> can include metal pipes, such as pipes constructed from carbon steel. The insulation layer <NUM> can include a range of thicknesses. For example, the insulation layer can be <NUM>"-<NUM>",. <NUM>"-<NUM>", <NUM>"-<NUM>", and/or <NUM>"-<NUM>" thick. The insulation <NUM> can include calcium silicate insulation, mineral wool, glass wool, rigid foam, polyethylene insulation, or the like.

The corrosion and erosion monitoring system <NUM> can be positioned with respect to a first location <NUM> along the length of the pipe <NUM> for calibration and then can travel along the length of the pipe <NUM> to a second location <NUM> for inspection without having to be physically removed from the pipe <NUM> and redeployed in the second location <NUM> to perform corrosion and/or erosion inspection at the second location <NUM>.

As shown in <FIG>, the corrosion and erosion monitoring system <NUM> can include a modular acquisition system <NUM>. The modular acquisition system <NUM> incudes a crawler device <NUM> which can be configured with a processor, a controller, and a plurality of positioning mechanisms <NUM>. The modular acquisition system <NUM> also includes a radiographic source <NUM> and a radiographic detector <NUM>. The modular acquisition system <NUM> can be coupled via a communications interface <NUM> to a management system <NUM> including a display <NUM>.

The modular acquisition system <NUM> can be configured to receive one or more modular components for use in determining CUI. For example, a variety of different configurations of crawler devices <NUM>, radiographic sources <NUM>, and radiographic detectors <NUM> can be included in the modular acquisition system <NUM> depending on the inspection being performed and/or the dimensions or type of pipe being inspected. The various components of the modular acquisition system <NUM> can be interchangeably reconfigured without deviating from the methods of operations described herein.

The modular acquisitions system <NUM>, as shown in <FIG>, includes a crawler device <NUM>. The crawler device <NUM> can include a processor, a controller, and/or a memory. The memory can store computer-readable, executable instructions, which when executed by the processor can cause the controller to operate the crawler device, the radiographic source <NUM>, and/or the radiographic detector <NUM> according to the methods of operation that will be further described herein. The crawler device <NUM> can include a rigid, configurable frame or similar mechanisms to provide support for the components of the crawler device <NUM> so that they can be arranged in relation to the insulated pipe <NUM>. The crawler device <NUM> includes a plurality of positioning mechanism <NUM> which can be controlled by the controller and are operable to move, or otherwise position the modular acquisition system <NUM> along an axial or circumferential aspect of the insulated pipe. For example, the positioning mechanism <NUM> can include wheels, rollers, calipers, tracks, or the like which can operate to move the modular acquisition system <NUM> along the outside of the insulated pipe so that inspections can be performed at one or more locations along the length and the circumference of the pipe without having to remove the insulation <NUM> from the pipe <NUM>. The positioning mechanisms <NUM> can be further configured to enable the modular acquisition system <NUM> to travel along the insulated pipe at varying rates of speed. In some embodiments, the positioning mechanisms <NUM> can be configured to enable the modular acquisition system <NUM> to travel at a rate of at least <NUM> feet/hour. In some embodiments, the modular acquisition system <NUM> can include a global positioning system configured to generate global positioning system coordinate data such that the coordinate data can be included in any digital images of the insulated pipe. In this way, the corrosion monitoring system <NUM> can accurately determine one or more locations, relative to the insulated pipe, in order to perform calibration and/or inspection operations at the one or more locations.

As further shown in <FIG>, the modular acquisition system <NUM> includes a radiographic source <NUM>. The radiographic source <NUM> can include devices or mechanisms capable of generating and transmitting X-rays, and/or X-ray photons. In some embodiments, the radiographic source <NUM> can be configured to generate and transmit gamma rays. The radiation emitted from the radiographic source <NUM> is transmitted through the insulation <NUM> and the pipe <NUM> and is received by the radiographic detector <NUM>. The radiographic detector <NUM> can include indirect flat panel detectors and direct flat panel detectors which can be configured opposite from the radiographic source <NUM> to receive the emitted radiation and generate a digital image corresponding to the insulation <NUM> and the pipe <NUM>. The digital image can then be output from the modular acquisition system <NUM> to determine a measure of CUI occurring within the pipe <NUM>. In some embodiments, the radiographic detector <NUM> can output the digital image via a wireless communication mechanism configured within the radiographic detector <NUM>.

The modular acquisition system <NUM> can be operably connected to the management system <NUM> via a communications interface <NUM>. In some embodiments, the communications interface <NUM> include a wired communications interface <NUM>. In some embodiments, the communications interface can include a wireless commutations interface <NUM>.

As further shown in <FIG>, the modular acquisition system <NUM> is coupled via the communications interface <NUM> to a management system <NUM>. The management system <NUM> can include a processor and a memory and can be coupled to a display, such as display <NUM>. The memory can store computer-readable, executable instructions, which when executed, cause the processor to receive the digital image from the modular acquisition system and to process the digital image to determine an amount of corrosion and/or erosion present under the insulation <NUM> within the pipe <NUM>. The management system <NUM> can also include one or more software applications which include visualization and repair functionality associated with one or more pipes <NUM> for which an amount of corrosion, erosion, and/or material loss from a wall of the pipe <NUM> has been determined. In some embodiments, the management system <NUM> can also include software functionality associated with calibrating and/or positioning the corrosion and erosion monitoring system <NUM> and/or the modular acquisition system <NUM> with respect to an insulated pipe. The management system <NUM> can be configured to output data pertaining to calibration or inspection operations performed using the corrosion and erosion monitoring system <NUM> to the display <NUM>. For example, in some embodiments, the management system <NUM> can provide data pertaining to inspected sections of the insulated pipe <NUM> as overlays in a three-dimensional computer-aided design (CAD) model of the insulated pipe <NUM>. In some embodiments, the management system <NUM> can include software functionality configured to cause the modular acquisition system <NUM> to perform calibration and inspection operations in an automated manner at one or more locations along the insulated pipe <NUM>. The management system <NUM> can also include software functionality configured to cause the display <NUM> to auto-generate calibration and/or inspection data, such auto-generating a color map for each digital image of the insulated pipe <NUM> captured by the modular acquisition system <NUM>.

<FIG> is a process diagram illustrating an example process <NUM> performed by a corrosion and erosion monitoring and/or inspection system, such as the corrosion and erosion monitoring system <NUM> described in relation to <FIG> and configured to determine an amount of wall loss within an insulated pipe without requiring the insulation to be removed. The example process <NUM> described in <FIG>, describes a process for inspecting an insulated pipe <NUM> to determine an amount of corrosion and/or erosion in the pipe wall using the corrosion and erosion monitoring system <NUM> of <FIG>. The example process <NUM> described in <FIG> with regard to inspection operations will also be described in association with an example process <NUM>, illustrated in <FIG>, described with regard to calibration operations.

At operation <NUM>, the modular acquisition system <NUM> acquires a calibration image of a pipe wall at a first location <NUM> of an insulated pipe <NUM>. The management system <NUM> can cause the modular acquisition system <NUM> to acquire the calibration image in response to user input and/or one or more configuration settings triggering the modular acquisition system <NUM> to initiate calibration operations with respect to a new inspection to be performed. Calibration of the corrosion and erosion monitoring system <NUM> is important for determining an amount of CUI and necessary in order to calculate an amount of wall loss at a particular location of the insulated pipe <NUM> during an inspection operation. In response to initiating a calibration operation, the management system <NUM> can execute instructions causing the modular acquisition system <NUM> to emit radiation into the insulated pipe <NUM> and to cause the radiographic detector <NUM> to transmit the calibration image to the management system <NUM>.

At operation <NUM>, the management system <NUM> receives the calibration image and performs operations to generate a calibration model of the pipe <NUM> wall at the first location <NUM> based on the calibration image. In order to accurately determine the amount of corrosion and/or erosion and an amount of wall loss in the pipe <NUM>, the management system <NUM> can utilize the calibration image acquired in operation <NUM> to generate a calibration model of the pipe <NUM>. The calibration model can be a mathematical model or data structure that is used to determine a thickness of the pipe <NUM> wall in the calibration image. The calibration model can further include inputs of various properties of the pipe <NUM> and can be used by the management system <NUM> to determine geometric parity between the calibration image and subsequently acquired inspection images. By accounting for the geometric properties of the pipe <NUM>, the determination of an amount of CUI or an amount of wall loss in the pipe <NUM> can be accurately determined between calibration images and inspection images. Further description of the calibration operations performed by the corrosion and erosion monitoring system <NUM> to generate the calibration model will now be described in relation to <FIG>.

<FIG> is a process flow diagram illustrating an example process <NUM> for calibrating the corrosion and erosion monitoring system of <FIG> to generate a calibration model as described in relation to operation <NUM> of <FIG> in order to determine an amount of wall loss within an insulated pipe without requiring the insulation to be removed. The process <NUM> begins after a calibration image has been acquired as described in relation to operation <NUM> of <FIG>. In operation <NUM> of <FIG>, the management system <NUM> acquires one or more pipe properties. The one or more pipe properties can include, but are not limited to, a pipe inner diameter, a pipe outer diameter, a pipe material, a pipe insulation material, an insulation material thickness, and a presence of fluid in the pipe <NUM>. The properties of pipe <NUM> can be provided to the management system <NUM> by a user, by a configuration setting associated with an inspection of a previous pipe <NUM> at the same location <NUM> or at a different location. In some embodiments, the pipe properties can be acquired based on GPS coordinate data associated with the location along the pipe <NUM> at which the calibration/inspection operations are occurring.

In operation <NUM>, the management system <NUM> generates a pipe wall model. The pipe wall model can be a graphical model, an algorithmic model, a data structure, or the like representing the dimensional attributes of the pipe <NUM> and the insulation <NUM>. The management system <NUM> constructs the pipe wall model based on the pipe properties acquired in operation <NUM> and uses the generated pipe wall model as a basis for subsequent calibration operations necessary to generate the calibration model that will be used to determine the CUI or amount of wall loss occurring in the pipe <NUM> using inspection image data. During operation <NUM>, the management system <NUM> determines a thickness of the pipe, t<NUM>, and the thickness of the insulation, t<NUM>, at different radial distances along the circumference of the pipe <NUM> and the insulation <NUM>.

In operation <NUM>, the management system <NUM> determines a profile of the pipe wall in the calibration image. In order to identify the pipe <NUM> in the calibration image, the management system <NUM> generates multiple line profiles for the portion of the pipe <NUM> depicted in the calibration image. For example, the management system <NUM> generates line profiles associated with a left, right, and center perspective of the pipe <NUM> in the calibration image. In some embodiments, the management system <NUM> can generate line profiles for other perspectives of the pipe and is not limited to the left, right, and center perspectives. In some embodiments, the management system <NUM> can generate a continuous line profile. The management system <NUM> can then average the various line profiles to compute an average line profile for the pipe <NUM>. Based on determining the minimum pixel intensity value at each end of the average line profile, the segment of pipe <NUM> that was imaged can be determined.

In operation <NUM>, the management system <NUM> performs a geometric calibration of the pipe wall in the calibration image. The geometric calibration associates or scales the calibration image to the pipe wall model generated in operation <NUM>. First, the management system <NUM> correlates points associated with the outer diameter of the pipe <NUM> in the calibration image to the actual dimensions in the pipe wall model. Next, the management system <NUM> computes linear interpolation coefficients for the pipe wall as a method of curve fitting. Finally, the management system <NUM> maps the intensity profile from the calibration image onto the pipe wall model.

In operation <NUM>, the management system <NUM> determines one or more attenuation coefficients of the pipe wall in the calibration image. In some embodiments, the calibration model can include an attenuation coefficient associated with the pipe wall at the first location, and an attenuation coefficient of insulation at the first location. In some embodiments, the calibration models can include an attenuation coefficient for a fluid present within the pipe. The attenuation coefficients characterize the ease or difficulty for which a volume of material can be penetrated by the radiographic energy emitted from the radiographic source <NUM>. Because the pipe <NUM> wall and the pipe insulation <NUM> can have different material properties, their attenuation coefficients can differ and thus be used to compute the thickness of the pipe wall and pipe insulation for subsequent use in determining CUI or an amount of material loss from within the pipe <NUM>. The attenuation coefficients associated with the pipe wall and insulation can be determined using the Beer-Lambert law which states that the absorbance of a material is directly propositional to the thickness of the material. An example of computing the attenuation coefficient for the pipe wall is as follows.

Initially, the intensity values associated with the radiographic energy transmitted through the center of the pipe <NUM> and at the interface between the pipe <NUM> and the insulation <NUM> can be computed.

The intensity value of the radiographic energy transmitted through the center of the pipe can be determined using equation (<NUM>) shown below.

In equation (<NUM>), the ratio of the intensity of the radiographic energy after passing through the center of the pipe <NUM>, I, and the intensity of the radiographic energy before passing through the center of the pipe <NUM>, I<NUM>, can be used to determine the effective attenuation coefficient, µeff, and the total thickness of the pipe <NUM> including the insulation <NUM>, ttot.

Equation (<NUM>) can be further solved to determine the total thickness of the pipe <NUM> and the insulation <NUM>, as shown in equation (<NUM>) below.

The effective attenuation coefficient, µeff, for the total thickness of the pipe <NUM>, ttot, can thus be represented in equation (<NUM>) below.

The effective attenuation coefficient, µeff, can thus be determined for the radiographic energy passing through the center of the pipe <NUM> as shown in equation (<NUM>).

Applying the Beer-Lambert law in regard to the radiographic energy detected in the calibration image at the interface between the pipe <NUM> and the insulation <NUM>, the attenuation coefficient for the pipe <NUM>, µ<NUM>, and the attenuation coefficient for the insulation <NUM>, µ<NUM>, can be similarly determined as shown in equations (<NUM>) and (<NUM>) below. <MAT> <MAT>.

In operation <NUM>, based on determining the attenuation coefficient, µ<NUM>, of the pipe <NUM> wall, the management system <NUM> determines a calibration thickness of the pipe wall in the calibration image. Once determined, the thickness of the pipe wall determined in the calibration image can be used to determine the thickness of the pipe wall in subsequent inspection images. Equations (<NUM>) and (<NUM>) below can be utilized to solve for the pipe <NUM> thickness, t<NUM>. <MAT> <MAT>.

As a result, the pipe <NUM> thickness in the calibration image, t<NUM>, can be solved as shown in equation (<NUM>) below.

Having completed the calibration process described in relation to operations <NUM>-<NUM> of <FIG>, the management system <NUM> can continue operations to determine an amount of CUI or wall loss in pipe <NUM> during inspection operations described in relation to <FIG>.

In operation <NUM>, based on generating the calibration model of the pipe <NUM> wall and determining a thickness of the pipe <NUM> wall using the calibration image associated with the first location <NUM>, the management system <NUM> can execute instructions, which when executed, cause the modular acquisition system <NUM> to acquire an inspection image of the pipe <NUM> wall at the second location <NUM>. The modular acquisition system <NUM> acquires the inspection image in a similar manner as the calibration image was acquired and was described in operation <NUM> of <FIG>. In operation <NUM>, the radiographic source <NUM> emits radiographic energy into the pipe <NUM> and the insulation <NUM> that can be captured by the radiographic detector <NUM> as an inspection image. The radiographic detector <NUM> can transmit the inspection image to the management system <NUM> for use in determining an amount of corrosion and/or erosion present in the pipe <NUM> wall.

In operation <NUM>, the management system <NUM> receives the transmitted inspection image and determines an inspection thickness of the pipe <NUM> wall at the second location <NUM>. The management system <NUM> determines the inspection thickness of the pipe <NUM> wall at the second location based on completing operations <NUM>-<NUM> described in <FIG> but as applied to the inspection image acquired during operation <NUM> of an inspection operation. As a result, the management system <NUM> can determine the inspection thickness of the pipe <NUM> wall using equation (<NUM>) above but now applied to the intensity values associated with the inspection image.

In operation <NUM>, the management system <NUM> can determine a wall loss measurement of the pipe <NUM> wall at the second location <NUM>. Having computed the wall thickness, t<NUM>, for the inspection image, the measure of wall loss can be determined as the difference of the wall thickness determined in relation to the calibration image acquired during the calibration operation and the wall thickness determined in relation to the inspection image acquired during the inspection operation.

In operation <NUM>, the management system <NUM> outputs the wall loss measurement. For example, the management system <NUM> can output the wall loss measurements to one or more software applications configured to provide visualization and repair functionality. The wall loss measurements can be output for display, such as on display <NUM> and can be provided to users as a color map with appropriate coloring or shading to indicate where changes in the thickness of the pipe wall may be present at the second location <NUM>. The color map generated by the management system <NUM> can represent an improved graphical user interface for presenting an amount of CUI and/or an amount of wall loss within a pipe because the color map provides a novel, intuitive, easy-to-interpret presentation of the wall loss data acquired during an inspection of an insulated pipe.

<FIG> illustrate an exemplary implementation of performing calibration and inspection operations on an insulated pipe using the corrosion and erosion monitoring system of <FIG> according to one or more of the methods described in relation to <FIG> and <FIG>.

As shown in <FIG>, the modular acquisition system <NUM> is positioned at a first location <NUM> with respect to the pipe <NUM> that is covered by insulation <NUM> and acquires a calibration image <NUM> at the first location according to operation <NUM> described in relation to <FIG>. The radiographic source <NUM> emits radiographic energy through the pipe <NUM> and the insulation <NUM> which is received by radiographic detector <NUM>. A digital image, the calibration image <NUM>, is transmitted from the modular acquisition system <NUM>, via communications interface <NUM>, to the management system <NUM>. The calibration image <NUM> includes GPS coordinate data corresponding to the first location <NUM>.

The management system <NUM> can then commence calibration operations to generate a calibration model of the pipe <NUM> wall by acquiring one or more pipe properties <NUM> according to operation <NUM> described in relation to <FIG>. The management system <NUM> can generate a pipe wall model <NUM> according to operation <NUM> described in relation to <FIG>. The pipe wall model <NUM> can include measurements of the thickness of the pipe <NUM>, e.g., t<NUM>, and measurements of the thickness of the insulation <NUM>, e.g., t<NUM>. The thickness measurements can be determined at different radial distances extending around the circumference of the pipe <NUM> and the insulation <NUM>.

As shown in <FIG>, the management system <NUM> determines a profile of the pipe wall in the calibration image according to operation <NUM> described in relation to <FIG>. The intensity values associated with the pixels in the calibration image <NUM> are used to generate line profiles corresponding to different aspects from which the radiographic energy was emitted by the radiographic source <NUM> and transmitted through the pipe <NUM> and insulation <NUM>. For example, line profile <NUM> can be associated with the left aspect of the calibration image <NUM>, line profile <NUM> can be associated with the right aspect of the calibration image <NUM>, and line profile <NUM> can be associated with the central aspect of the calibration image <NUM>. As shown in <FIG>, the management system <NUM> can compute an average line profile <NUM> based on the three different line profiles descried in relation to <FIG>. In <FIG>, the management system <NUM> completes the determination of the pipe wall profile in the calibration image by determining the minimum intensity values present at each end of the average line profile. As shown in <FIG>, the management system determines that points <NUM> and <NUM> correspond to the minimum intensity values and can thereby be used to identify a portion or segment of the pipe <NUM>.

In <FIG>, the management system <NUM> performs a geometric calibration of the pipe wall in the calibration image <NUM> according to operation <NUM> described in relation to <FIG>. The geometric calibration associates the minimum intensity values <NUM> and <NUM> from the calibration image <NUM> to actual dimensions <NUM> and <NUM>, respectively. The management system <NUM> can further determine linear interpolation coefficients such that the thicknesses of the pipe <NUM>, t<NUM>, and the insulation, t<NUM>, can be determined by mapping or curve fitting the pixel value intensity profiles over the calibration model of the pipe <NUM> and the insulation <NUM>.

In <FIG>, the management system <NUM> can determine one or more attention coefficients of the pipe wall in the calibration image <NUM> according to operation <NUM> described in relation to <FIG>. As shown in <FIG>, the management system <NUM> determines the pixel intensity value <NUM> at the center of the pipe and also the pixel intensity values <NUM> and <NUM> which are associated with the interface between the pipe <NUM> and the insulation <NUM>. The pixel intensity values can be used to determine the one or more attenuation coefficients based on the correlation between the magnitude of the pixel intensity value and the intensity of the radiographic energy transmitted through the pipe <NUM> and the insulation <NUM>.

In <FIG>, the management system <NUM> can compute the attenuation coefficients of the pipe <NUM> (e.g., µ<NUM>) and the insulation <NUM> (e.g., µ<NUM>) by utilizing the Beer-Lambert law described in relation to operation <NUM> of <FIG>. Using the Beer-Lambert law, the intensity of the radiographic energy that is applied to the pipe <NUM> (I<NUM>) can be evaluated with respect to the intensity of the radiographic energy that passes through the pipe <NUM> (I) such that the attenuation coefficients for the pipe <NUM> (e.g., µ<NUM>) and the insulation <NUM> (e.g., µ<NUM>) can be determined using the previously described equations (<NUM>) and (<NUM>). As a result of determining the attenuation coefficients for the pipe <NUM> and the insulation <NUM>, the management system <NUM> can determine a calibration thickness of the pipe wall (e.g., t<NUM>) based on the calibration image according to operation <NUM> as described in relation to <FIG> and using the previously described equation (<NUM>).

As shown in <FIG>, having completed the calibration operations, the management system <NUM> can execute instructions causing the modular acquisition system <NUM> to acquire an inspection image <NUM> of the pipe <NUM> and the insulation <NUM> at the second location <NUM> according to operation <NUM> described in relation to <FIG>. The inspection image <NUM> is transmitted via communications interface <NUM> to the management system <NUM>. The management system <NUM> can then determine an inspection thickness according to operation <NUM> described in relation to <FIG>. The inspection thickness (e.g., t<NUM> and t<NUM> shown in <NUM>) can be determined in a manner analogous to operations <NUM>-<NUM> described in relation to <FIG>, except the geometric calibration, the one or more attenuation coefficients, and the thickness of the pipe are determined with respect to the inspection image <NUM>. A wall loss measurement can be computed based on the inspection image <NUM> according to operation <NUM> described in relation to <FIG>. The wall loss measurement can be determined as a difference in the calibration thickness of the pipe <NUM> and the inspection thickness of the pipe <NUM>. As further shown in <FIG>, the management system <NUM> can output <NUM> the wall loss measurement for display.

The corrosion and erosion monitoring system <NUM> can continue to acquire inspection images and determine wall loss measurements at other locations along the same portion of pipe which included the first and second locations. In some embodiments, the corrosion and erosion monitoring system <NUM> can be redeployed to or reconfigured on a different portion of pipe. The new portion of pipe can include a third location which is different than the first and second locations. In some embodiments, the corrosion and erosion monitoring system <NUM> can cause the modular acquisition device <NUM> to be repositioned based on determining a change in the wall loss measurement at the third location <NUM> as compared to the second location. In this example, the management system <NUM> can reposition the modular acquisition device <NUM> to initiate calibration operations at the third location and subsequently perform inspection operations at a fourth location. The fourth location different than the third location and included in a different portion of pipe than the first and second locations. In this way, the corrosion and erosion monitoring system <NUM> can perform inspections along portions of an insulated pipe in an automated manner without requiring manual intervention or operator assistance to recalibrate the modular acquisition system <NUM> for subsequent inspection operations at different locations along the length of the pipe.

<FIG> is an exemplary graphical user interface (GUI) <NUM> displaying an amount of corrosion and/or erosion in an insulated pipe as output by the corrosion and erosion monitoring system <NUM> of <FIG>. The GUI <NUM> shown in <FIG> can be a GUI displayed within one or more applications which can configured on the management system <NUM> to provide visualization and repair functionality. In some embodiments, the applications can be configured on the same computing device as the management system <NUM>. In some embodiments, the applications can be configured in a web-browser on a computing device that is connected to the management system <NUM> but located remotely from the management system <NUM>. In some embodiments, the applications can be configured to generate a three-dimensional CAD model depicting one or more pipes within an oil and gas production facility and the GUI <NUM> can include functionality allowing a user to navigate, zoom in or out, highlight or select, aspects of the pipe <NUM> displayed within the GUI <NUM>.

As shown in <FIG>, the GUI <NUM> displays a horizontal cross-section of a pipe <NUM> and the insulation <NUM>. The GUI <NUM> displays the wall loss measurements determined at the upper <NUM> and lower <NUM> portions of the walls of pipe <NUM> as a color map that is provided in the GUI as a visualization layer or graphical overlay atop the inspection image, such as inspection image <NUM> of <FIG>. In some embodiments, the GUI <NUM> can be displayed as a visualization layer or graphical overlay atop a three-dimensional CAD model depicting one or more pipes <NUM> associated with an oil and gas production facility at which the inspection operations were performed.

The GUI <NUM> improves the operation of a computing device to visualize wall loss measurements due to corrosion and/or erosion in an insulated pipe as an intuitive color map that can be automatically generated during an inspection operation. Without the color map, viewing the subtle variations in the pipe dimensions as a result of corrosion and/or erosion within the pipe <NUM> would be very difficult to interpret accurately in order to properly diagnose corrosion and/or erosion conditions and organize repair of the corrosion and/or erosion within the pipe <NUM>. Thus, the GUI <NUM> can be integrated into the practical application of determining an amount of wall loss within an insulated pipe using digital radiography at a plurality of locations along the length of the insulated pipe. The GUI <NUM> enhances this application by automatically generating inspection images and updating the color map displayed in the GUI <NUM> in an automated manner with respect to the inspection images.

<FIG> is a block diagram of a computing system <NUM> suitable for use in implementing the computerized components described herein. In broad overview, the computing system <NUM> includes at least one processor <NUM> for performing actions in accordance with instructions, and one or more memory devices <NUM> and/or <NUM> for storing instructions and data. The illustrated example computing system <NUM> includes one or more processors <NUM> in communication, via a bus <NUM>, with memory <NUM> and with at least one network interface controller <NUM> with a network interface <NUM> for connecting to external devices <NUM>, e.g., a computing device (such as a controller or a modular acquisition system). The one or more processors <NUM> are also in communication, via the bus <NUM>, with each other and with any I/O devices at one or more I/O interfaces <NUM>, and any other devices <NUM>. The processor <NUM> illustrated incorporates, or is directly connected to, cache memory <NUM>. Generally, a processor will execute instructions received from memory. In some embodiments, the computing system <NUM> can be configured within a cloud computing environment, a virtual or containerized computing environment, and/or a web-based microservices environment.

In more detail, the processor <NUM> can be any logic circuitry that processes instructions, e.g., instructions fetched from the memory <NUM> or cache <NUM>. In many embodiments, the processor <NUM> is an embedded processor, a microprocessor unit or special purpose processor. The computing system <NUM> can be based on any processor, e.g., suitable digital signal processor (DSP), or set of processors, capable of operating as described herein. In some embodiments, the processor <NUM> can be a single core or multi-core processor. In some embodiments, the processor <NUM> can be composed of multiple processors.

The memory <NUM> can be any device suitable for storing computer readable data. The memory <NUM> can be a device with fixed storage or a device for reading removable storage media. Examples include all forms of non-volatile memory, media and memory devices, semiconductor memory devices (e.g., EPROM, EEPROM, SDRAM, flash memory devices, and all types of solid state memory), magnetic disks, and magneto optical disks. A computing device <NUM> can have any number of memory devices <NUM>.

The cache memory <NUM> is generally a form of high-speed computer memory placed in close proximity to the processor <NUM> for fast read/write times. In some implementations, the cache memory <NUM> is part of, or on the same chip as, the processor <NUM>.

The network interface controller <NUM> manages data exchanges via the network interface <NUM>. The network interface controller <NUM> handles the physical and data link layers of the Open Systems Interconnect (OSI) model for network communication. In some implementations, some of the network interface controller's tasks are handled by the processor <NUM>. In some implementations, the network interface controller <NUM> is part of the processor <NUM>. In some implementations, a computing device <NUM> has multiple network interface controllers <NUM>. In some implementations, the network interface <NUM> is a connection point for a physical network link, e.g., an RJ <NUM> connector. In some implementations, the network interface controller <NUM> supports wireless network connections and an interface port <NUM> is a wireless receiver/transmitter. Generally, a computing device <NUM> exchanges data with other network devices <NUM>, such as computing device <NUM>, via physical or wireless links to a network interface <NUM>. In some implementations, the network interface controller <NUM> implements a network protocol such as Ethernet.

The other computing devices <NUM> are connected to the computing device <NUM> via a network interface port <NUM>. The other computing device <NUM> can be a peer computing device, a network device, or any other computing device with network functionality. For example, a computing device <NUM> can be a controller, a modular acquisition system, and/or a management system as configured within the corrosion monitoring system illustrated in <FIG>. In some embodiments, the computing device <NUM> can be a network device such as a hub, a bridge, a switch, or a router, connecting the computing device <NUM> to a data network such as the Internet.

In some uses, the I/O interface <NUM> supports an input device and/or an output device (not shown). In some uses, the input device and the output device are integrated into the same hardware, e.g., as in a touch screen. In some uses, such as in a server context, there is no I/O interface <NUM> or the I/O interface <NUM> is not used. In some uses, additional other components <NUM> are in communication with the computer system <NUM>, e.g., external devices connected via a universal serial bus (USB).

The other devices <NUM> can include an I/O interface <NUM>, external serial device ports, and any additional co-processors. For example, a computing system <NUM> can include an interface (e.g., a universal serial bus (USB) interface, or the like) for connecting input devices (e.g., a keyboard, microphone, mouse, or other pointing device), output devices (e.g., video display, speaker, refreshable Braille terminal, or printer), or additional memory devices (e.g., portable flash drive or external media drive). In some implementations an I/O device is incorporated into the computing system <NUM>, e.g., a touch screen on a tablet device. In some implementations, a computing device <NUM> includes an additional device <NUM> such as a co-processor, e.g., a math co-processor that can assist the processor <NUM> with high precision or complex calculations.

Without in any way limiting the scope, interpretation, or application of the claims appearing below, a technical effect of one or more of the example implementations disclosed herein may include, for example, by utilizing digital radiography and a corrosion and erosion monitoring system including a mobile, modular acquisition system, some implementations of the current subject matter can enable more accurate detection and remediation of corrosion and/or erosion or wall loss within an insulated pipe at one or more locations of a pipe within an operational pipeline. Some implementations of the current subject matter can enable the corrosion and erosion monitoring system to perform calibration and inspection operations at multiple locations along the length of an insulated pipe, without requiring the insulation of the pipe to be removed during inspection and without removing the modular acquisition system from the pipe entirely for redeployment at subsequent locations. As compared to some conventional systems, some implementations of the current subject matter can enable corrosion and/or erosion monitoring, inspection, and repair operations or solutions that may be less expensive; require fewer resources, and are less disruptive to pipeline production operations. Further, some implementations of the current subject matter can enable rapidly inspecting and diagnosing corrosion and/or erosion conditions within a pipe as a result of the automated calibration and inspection operations that the corrosion and erosion monitoring system is configured to perform. Some implementations of the current subject matter can also improve the safety of inspection and repair operations as a result of displaying accurate location information and corrosion and/or erosion data, via the GUI configured within one or more applications including visualization and repair functionality, prior to the inspection and repair operations.

To provide for interaction with a user, one or more aspects or features of the subject matter described herein can be implemented on a computer having a display device, such as for example a cathode ray tube (CRT) or a liquid crystal display (LCD) or a light emitting diode (LED) monitor for displaying information to the user and a keyboard and a pointing device, such as for example a mouse or a trackball, by which the user may provide input to the computer. For example, feedback provided to the user can be any form of sensory feedback, such as for example visual feedback, auditory feedback, or tactile feedback; and input from the user may be received in any form, including acoustic, speech, or tactile input. Other possible input devices include touch screens or other touch-sensitive devices such as single or multi-point resistive or capacitive trackpads, voice recognition hardware and software, optical scanners, optical pointers, digital image capture devices and associated interpretation software, and the like.

Claim 1:
A computer-implemented method comprising:
acquiring (<NUM>) a calibration image of a pipe wall at a first location (<NUM>) of an insulated pipe (<NUM>);
generating (<NUM>) a calibration model of the pipe wall at the first location (<NUM>) based on the calibration image, the calibration model including an attenuation coefficient associated with the pipe wall at the first location (<NUM>), an attenuation coefficient of insulation (<NUM>) at the first location, and the calibration thickness of the pipe wall at the first location (<NUM>) in the calibration image;
acquiring (<NUM>) an inspection image of the pipe wall at a second location (<NUM>) of the insulated pipe (<NUM>), the second location (<NUM>) different than the first location (<NUM>);
determining (<NUM>) an inspection thickness of the pipe wall at the second location (<NUM>) based on applying the attenuation coefficient associated with the pipe wall at the first location (<NUM>) and the attenuation coefficient of insulation (<NUM>) at the first location (<NUM>) to the inspection image;
determining (<NUM>) a wall loss measurement of the pipe wall at the second location (<NUM>), the wall loss measurement determined based on a difference of a calibration thickness of the pipe wall at the first location (<NUM>) and the determined inspection thickness, the wall loss measurement characterizing an amount of wall loss in the insulated pipe (<NUM>) at the second location (<NUM>); and
outputting (<NUM>) the wall loss measurement;
wherein the acquiring steps are performed by a modular acquisition system (<NUM>) including a radiographic source (<NUM>), a radiographic detector (<NUM>), and a crawler device (<NUM>) including a processor, a controller, and a plurality of positioning mechanisms (<NUM>) configured to position the radiographic source (<NUM>) and the radiographic detector (<NUM>) at one or more locations along the length of the pipe (<NUM>).