Early detection of corrosion under insulation

Abstract

The present invention relates to a method for monitoring defects in a pipeline section and / or vessel having an insulation layer. A sensor line, including a single optical fiber or a bundle of optical fibers, is mounted along the length of the pipeline section or on the surface of the vessel and positioned outside the insulation layer. The sensor line is operably coupled to a temperature sensing (DTS or FBG based) system. The method determines, via the temperature sensing system, an external temperature profile over the length of the pipeline section or surface of the vessel. Defects are detected based on an analysis of the measured external temperature profile and a locally averaged external temperature profile along the length of the pipeline section or surface on the vessel.

Description

[Technical field]

[0001] The present invention relates to a method for monitoring defects in pipelines and / or vessels having an insulation layer, preferably above or below ground, and non-subsea insulation layers.The present invention relates to a corrosion monitoring method, and more particularly to a permanently installed monitoring system for corrosion under insulation (PIMSCUI).

[0002] In a second aspect, the present invention also relates to a system for monitoring defects in insulated pipes and / or vessels, preferably configured for use in the method of the first aspect of the invention.

[0003] In a third aspect, the present invention relates to the use of a method and / or system according to the first and second aspects of the invention for monitoring defects, in particular corrosion monitoring, in insulated pipeline sections and / or vessels.

[0004] The present invention relates to the technical field of protection of pipes or pipe joints against corrosion or deposits. [Background technology]

[0005] Like other means of transportation essential to the global economy, pipelines are essential to link points of production to points of consumption. Pipelines provide an efficient means of transporting chemicals, feed, food, oil, water, and natural gas between reactors, as well as between production sites, refineries, processing plants, and to consumers. Vessels and tanks are of similar importance in many industrial, agricultural, and other processes.

[0006] Due to their importance in providing access to oil, fuel, and other materials, it is important that pipelines / vessels are subject to limited integrity failures. Such integrity failures may be precipitated by material defects (e.g., leaks or cracks), external forces (e.g., disruption due to human error), or internal issues such as corrosion.

[0007] The main problem can occur when corrosion starts to spread under the insulation, known as corrosion under insulation (CUI). Corrosion is caused by the interaction of water with the pipeline. There are two main sources of water. First, a weathering break can result in the penetration of water into the metal surface from external sources such as rainfall, drift from cooling towers, condensation drops from cold service equipment, vapor releases, process liquid spills, fire sprinklers, delge systems, sprays from lavatories, and condensation on cold surfaces after vapor barrier damage. Second, the main corrosion problem occurs in situations where there are cycling temperatures that vary from below the dew point to above ambient temperature. In this case, the classic wet / dry cycle occurs when the cold metal experiences water condensation and is then baked off during the hot / dry cycle. The transition from cold / wet to hot / dry involves an intermediate period of wet / warm conditions with high corrosion rates.

[0008] When pipes carrying flammable or explosive fluids are damaged by corrosion, the damage can lead to serious accidents. Avoiding CUI is a major challenge, for example, in the oil and chemical industries. Operators cannot predict where CUI will occur, so they have to regularly inspect hundreds of kilometers of insulated piping manually. If left unmanaged, CUI usually results in several plant problems, including unscheduled shutdowns, and subsequently costly maintenance and repair operations.

[0009] Moisture sensors exist in all shapes and types, but have significant drawbacks that limit their usefulness in many environments prone to corrosion under insulation. Visual inspection is still often used, but also has significant drawbacks. In addition to being less efficient, the fibrous nature of traditional insulation materials causes moisture to diffuse via capillary action to areas beyond the process entry point. Corrosion also occurs in areas where the envelope would appear unaffected, which is impossible to control by visual inspection.

[0010] China Patent Application Publication No. 111022833 discloses a leak monitoring system for pipelines with thermal insulation layers that uses optical fibers to measure temperature. In case of a leak, the optical fibers measure the sudden increase in temperature and convert the optical signal into a temperature signal that is sent to a DTS system. The system issues an alarm and identifies the leak point.

[0011] U.S. Patent Application Publication No. 2010319435 discloses a technique that facilitates the detection of moisture in insulation using a system with two distributed sensor lines routed along the inside and outside of an insulation layer to determine the differential temperature along the layer.

[0012] EP 3126808 A1 discloses an acoustic source configured to generate an acoustic signal at a metal surface, which interacts with a fiber optic cable and affects a property of the light, and a signal processing unit configured to determine the location of the change in the metal surface based on the change in the property of the signal.

[0013] Some methods for determining defects and / or corrosion in insulated pipes are destructive or non-destructive and cannot be installed after the equipment is in operation. Furthermore, their use in semi-continuous or batch systems can lead to many false positive errors. Methods based on acoustic signals require additional placement of acoustic emitters along the length of the pipeline. Summary of the Invention [Problem to be solved by the invention]

[0014] The present invention aims to overcome at least some of the problems and drawbacks mentioned above.The object of the present invention is to provide a method which eliminates these drawbacks. [Means for solving the problem]

[0015] The present invention and its embodiments serve to provide a solution to one or more of the above mentioned drawbacks. To this end, the invention relates to a method for monitoring defects in a pipeline and / or vessel having an insulation layer according to claims 1 to 21. The main object of the invention is to provide a permanently installed monitoring system for corrosion under insulation (PIMSCUI) and a method for performing the monitoring of said system.

[0016] The present invention is particularly focused on non-subsea pipelines and containers, above or below sea level. Subsea vessels are surrounded by a medium that has an essentially constant temperature, with essentially no spatial (uniform temperature at various depths, little variation in the horizontal plane) or temporal variations in said temperature (no day-night cycle or substantial effect of the sun). It is these variations, among others, that make the present invention suitable for non-subsea applications.

[0017] In the following, reference is often made to pipelines and pipeline sections, and for the sake of simplicity this will be taken to also include vessels, unless otherwise stated.

[0018] In one aspect, a permanently installed fiber optic technology for monitoring corrosion under insulation (PIMSCUI) continuously over a large surface area is provided. The technology revolves around discrete or continuous moisture under insulation monitoring using optical fiber alone or in combination with direct measurement for CUI. Expected temperature values ​​are determined based on several parameters such as insulation properties, environmental factors, etc. Insulation defects can be detected when the measured temperatures deviate from their expected values.

[0019] In a preferred embodiment, the detection of defects is further based on the known thickness and thermal conductivity of the insulation layer around the pipeline section. Note that this can be a thickness profile and / or thermal conductivity profile along the length of the pipeline section in case of changes in diameter and / or thermal conductivity (e.g. differences in the type of insulation used). These parameters can be measured / checked periodically or can be assumed / known values ​​(e.g. based on construction plans) and used as such.

[0020] In another aspect, the invention relates to a system as claimed in claim 22. More specifically, the system serves to monitor defects in insulated pipes and vessels, comprising: - Fiber optic cable laid along the pipe wall of the insulated pipeline; - a laser source attached to the fiber optic cable and configured to transmit light pulses through the fiber optic cable; - a receiver attached to the fiber optic cable and configured to detect light pulses; a signal processing unit configured to determine the location of the penetration in the tube wall based on the change in the characteristics of the light pulses, the signal processing unit further taking into account several other parameters such as thermal insulation properties, environmental factors, etc.

[0021] In another aspect, the present invention relates to a use as claimed in claims 1 to 21 and / or claim 22. The use as described herein provides advantageous effects in terms of lower required measurements and the wide variety of systems in which it can be applied. [Brief description of the drawings]

[0022] [Figure 1] Figure 1: Schematic of an insulated pipeline [Diagram 2] Figure 2: Temperature difference over several meters of an insulated pipeline under different wet conditions [Diagram 3] FIG. 3: Cross-section of the preferred embodiment [Figure 4]FIG. 4: Cross-section of an alternative embodiment DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENTS

[0023] Description of the drawings Various aspects of the present disclosure are described more fully below with reference to the accompanying drawings. However, the present disclosure may be embodied in many different forms and should not be construed as limited to any specific structure or function presented throughout the present disclosure. Rather, these aspects are provided so that this disclosure will be thorough and complete, and will fully convey the scope of the disclosure to those skilled in the art. Based on the teachings herein, one skilled in the art should understand that the scope of the present disclosure is intended to cover any aspect of the present disclosure disclosed herein, whether implemented independently or in combination with any other aspect of the present disclosure. For example, an apparatus may be implemented and a method may be implemented using any number of the aspects set forth herein. In addition, the scope of the present disclosure is intended to cover such an apparatus or method implemented using other structures, functions, or structures and functions in addition to or other than the various aspects of the present disclosure described herein. It should be understood that any aspect of the disclosure disclosed herein may be embodied by one or more elements of a claim.

[0024] Figure 1 shows an insulated pipeline including a jacket and optical fiber. When a pipeline is insulated, the heat of the pipeline in the center of the insulation is conducted (through the insulation) to the outside of the pipeline, and vice versa for the reverse temperature profile. The magnitude and time decay of the pipeline temperature towards the outside of the pipeline depends on the thermal properties of the insulation. The most important thermal properties are the insulation thickness, thermal conductivity and heat capacity.

[0025] Corrosion is caused by the interaction of water with the pipeline. Water enters the insulation surrounding the pipeline through a breach in the weatherproof jacket. Water penetration results in wet insulation, and because water conducts heat more efficiently than air, progressive corrosion cells are created where the trapped heat accelerates the rate of corrosion. It is clear that wet conditions surrounding a pipeline cause pipeline CUI.

[0026] In Figure 2, the temperature profile along the outside of a pipeline monitored via the method and system of the present invention is shown in the curve marked with circles, with a temperature peak indicative of moisture ingress in the insulation surrounding the pipeline. The shape of this temperature peak can vary according to the location of the sensor cable, the type of vessel, the type and temperature of the fluid contained within or passing through the vessel, the constant or intermittent nature of the fluid passing through the vessel, the type of insulation used in the insulation layer, and other factors that affect the shape of the graph. The temperature profile of a pipeline without moisture ingress is also shown in the curve marked with triangles.

[0027] In this particular example, a fiber optic sensing cable is deployed adjacent to a 20 mm diameter pipeline with a liquid temperature 55°C higher than the outside temperature and insulated with 50 mm of rock wool (thermal conductivity 0.034 W / m·K at 10°C). The fiber optic sensing cable detects and measures the temperature along the length of the insulated pipe, as represented by the graph in Figure 2.

[0028] The curve with triangles shows the temperature measured with optical fiber on the outside of the insulated pipeline segment (0-2.4 m) when the insulation is dry. The temperature along the length of the insulated pipe is increased by 5°C compared to the unheated pipeline. The curve with circles shows the same temperature measurements when the insulation has 4% (volume %) of moisture injected in the 1-1.4 m zone, indicated by the dashed vertical line. In this wet segment from 1-1.4 m, the outside pipeline temperature is almost 30°C hotter than the ambient temperature (T∞). In the dry insulated zones (zones 0-1 m and 1.4-2.4 m), the wet insulated zone can be easily detected, since the temperature increase outside the pipeline is only 5°C. Due to the temperature sensing system (a distributed temperature sensing system or DTS system was used in the experiments, but alternatives such as a fiber Bragg grating (FBG)-based temperature sensing system measuring the temperature every minute are envisaged), the penetration of water in the insulation is detected at a very early stage, before the pipeline corrosion starts.

[0029] Figure 3 shows a cross section of a preferred embodiment. It shows a pipe 101 filled with a substance 102 (which can be liquid, gas, multi-phase or other) at a temperature higher or lower than the ambient air temperature. The pipe is surrounded by insulation 103 protected by a coating 104. The cladding may be made of aluminum. In a preferred embodiment, a fiber optic cable 105 is placed on the outside of the cladding.

[0030] FIG. 4 shows another embodiment in which a fiber optic cable 105 is placed between the insulation 103 and the cladding 104 . Other alternative embodiments: Fiber optic cable on the top, side, etc. of the pipe, rather than the bottom. Optical fiber somewhere in the insulation 103

[0031] It is clear that the method according to the invention and its application are not limited to the examples presented. The invention is not limited in any way to the embodiments described in the examples and / or shown in the figures. On the contrary, the method according to the invention can be realized in many different ways without departing from the scope of the invention.

[0032] Detailed Description of the Invention In the following detailed description section, specific embodiments of the present technology will be described. However, to the extent that the following description is specific to a particular embodiment or a particular use of the present technology, it is for illustrative purposes only and is intended to provide a description of an exemplary embodiment only. Thus, the present technology is not limited to the specific embodiments described below, but rather includes all alternatives, modifications, and equivalents that fall within the true spirit and scope of the appended claims.

[0033] The present invention relates to a system and method for preventing, detecting and managing corrosion under insulation in insulated equipment, such as vessels for holding and / or transporting fluids. The vessels can include pipelines, but also vessels such as tanks. For example, the system according to the present invention can be used along a length of insulated piping or other insulated equipment. The system operates by detecting moisture in the insulation via a continuous evaluation of temperature differences across the insulation or portions of the insulation surrounding the piping or other equipment. This automatic, continuous insulation evaluation provides an improved risk assessment for corrosion under insulation. The continuous evaluation also reduces the requirements for periodic inspection and maintenance in various plants, including, for example, oil and gas production / processing plants, refineries, chemical plants, and other plants that use insulated vessels in their plant operations.

[0034] In general, distributed sensor lines, such as distributed temperature sensing systems or fiber Bragg grating (FBG) sensing systems compatible sensor fibers or sensor cables, are deployed through or along the insulation surrounding piping or other equipment such that the sensor lines are separated by at least a portion of the insulation layer. The distributed or FBG sensor lines allow for distributed, continuous determination of the temperature difference across the insulation between the sensor lines, for example, via distributed temperature sensing techniques or FBG temperature sensing techniques. An initial temperature difference is established between the sensor lines as a baseline temperature difference. This allows for continuous detection of any changes in the temperature difference, which may indicate moisture infiltrating that particular area of ​​the insulation. For example, if an area of ​​the insulation is wetted by the intrusion of water or other wetting agent, the sensor lines will detect a decrease in the temperature difference in that area due to the reduced insulating properties of the insulation caused by the moisture.

[0035] As mentioned above, there are several existing technologies that can facilitate monitoring of pipelines for intrusion, including the use of acoustic or fiber optic technology, however, these technologies generally do not detect under-insulation corrosion in its early stages.

[0036] In a first approach of the invention, the invention relates to a method for monitoring defects in a non-subsea pipeline section or vessel above or below ground having an insulating layer, said defects being related to moisture ingress in the insulating layer, comprising the following steps: - mounting a sensor line, including a single optical fiber or a bundle of optical fibers, along the length of an insulated pipeline section or along the surface of an insulated vessel, outside the insulation layer; - operably coupling the sensor line to a temperature sensing system; - determining the external temperature profile over the length of an insulated pipeline section or over the surface of an insulated vessel via a temperature sensing system; - Detect surface defects in insulated pipeline sections or insulated vessels.

[0037] The method is characterized in that defects are detected based on a determined external temperature profile and a locally averaged external temperature profile along the length of an insulated pipeline section or over a surface of an insulated vessel, the locally averaged external temperature profile being determined for a point by averaging the determined external temperature profile over a predetermined perimeter length or surface for the point.

[0038] Preferably, said method is further characterized in that external information is collected, said external information comprising data on external heat / cold sources in the vicinity of the pipeline section or vessel and / or environmental data, said environmental data comprising meteorological information comprising local environmental temperature information, local precipitation information, local solar radiation information, wind information, said data on external heat / cold sources comprising at least the location of said external heat / cold sources. Defects are then detected based on said external information and the determined external temperature profile and the locally averaged external temperature profile along the length of the insulated pipeline section or over the surface of the insulated vessel.

[0039] Preferably, at least data regarding the external heat / cold source is used for detection and apart from the location may also include one or more of the temperature of the source or discharged material, flow rate, discharged material information, dimensions, orientation, type of source, etc.

[0040] In some instances, no such external source exists, in which case the environmental information becomes the dominant factor in the detection method.

[0041] Most preferably, however, both types of information / data are considered.

[0042] The terms "averaging" and "averaged" as used herein refer to any type of measure of central tendency, as used in statistics. This can refer to the use of median, mean (in multiple definitions such as arithmetic mean, geometric mean, harmonic mean, weighted arithmetic mean, truncated mean, quartile mean, triangular mean, etc., but preferably arithmetic mean), mode, mid-range, etc. In preferred embodiments, the median is used because it significantly reduces the effects of anomalies in the measurement (both inaccurate results and outliers due to certain circumstances).

[0043] The term "vessel" refers to any type of industrial equipment, such as a reactor tank, silo, etc., that forms a substantially enclosed volume (potentially having a pipeline associated with it).

[0044] The term "external heat / cold source" refers to a system or object that does not form part of a pipeline or vessel, has a temperature substantially different from its surroundings, and has a non-negligible effect on the temperature of its surroundings, including the temperature of the pipeline section / vessel. Typical sources are air / steam vents, industrial ovens, heating tapes, steam pipes, other pipelines / vessels, etc., but can also include thermal bridges connected to the pipeline / vessel. Such thermal bridges can be, for example, any contact support structure for the pipeline or vessel, such as a bracket, typically made of metal or other thermally conductive material.

[0045] In a preferred embodiment, defects are detected based on an external temperature profile determined over a predefined period of time. Preferably, this is based on a time-averaged difference between the locally averaged external temperature profile and the determined external temperature profile over said predefined period of time. The predefined period of time can vary depending on the circumstances and can be adjusted as necessary. It is preferably at least 5 minutes, 10 minutes, 15 minutes, 30 minutes, more preferably at least 1 hour or 2 hours, 4 hours, 6 hours, 12 hours, even more preferably at least 1 day, 2 days, 3 days, most preferably at least 1 week. Of course, longer periods such as 2 weeks, 1 month, etc. can be used. However, preferably, the period is kept relatively small, e.g. at most 1 month or less, so that changes in weather and such conditions remain limited (e.g. seasonal changes).

[0046] In a further preferred embodiment, the time-averaged difference excludes a period during said predetermined time period during which the determined external temperature profile differs from a reference temperature profile by less than a predetermined delta value, said reference temperature profile being preferably an environmental temperature, preferably an air temperature (for terrestrial applications), temperature in the vicinity of the pipeline section or vessel. Alternatively, the weight may be associated with a time period / measurement during which the weight is reduced depending on the situation, for example based on the temperature difference between the determined external temperature profile and the reference temperature profile. The smaller the difference, the less the weight. This can be done via a continuous weight function, but can also be discretized (a temperature difference between A and B results in a weight of X, a temperature difference between B and C results in a weight of Y, etc.).

[0047] In situations where the external temperature is relatively close to the temperature inside the pipeline, its effect on the determined external temperature profile (i.e. its difference with respect to the reference temperature profile) will be very small, and as a result the locally averaged external temperature profile may be obscured. For example, if for 90% of a given period the difference is very low and 10% is high, the measurable effect will be reduced by a factor of 10, which may result in an average result that does not indicate a defect. By removing such irrelevant data (by reducing it to the time for which the data is relevant, using, of course, an adjusted "valid" given period), reliable statistics can be generated for the time-averaged difference.

[0048] The predefined delta value can be set differently depending on the circumstances and can be adjusted automatically and / or manually. Preferably, this value is at least 0.10°C, or at least 0.25°C, more preferably at least 0.50°C, and even more preferably at least 1.0°C.

[0049] Other factors may contribute to slight, negligible, or even inconsistent, differences in temperature between the reference temperature profile and the determined external temperature profile. This can be solved, for example, by time-averaged differences that exclude or reduce the weight of the determined external temperature profile during a period in said predetermined time period, said period being determined based on one or more of the following: time of day, season, wind conditions, other weather conditions, pipeline or container usage parameters. Apart from the external temperature, further factors strongly affect the temperature of the sensor, resulting in negligible or even inconsistent external heat transfer. A more prominent factor is wind conditions. Typically, high winds, which also contribute other factors, effectively release any additional heat at the surface of the insulation where the sensor line is located, resulting in a small temperature difference at the sensor line relative to the surrounding environment. Another such factor is precipitation, which can also rapidly affect the temperature. Finally, if data on the use of the pipeline / container (e.g., temperature of the product inside), is available, this can also be used to determine periods during which the system is likely to receive no interesting data due to very small temperature differences between the inside and outside of the pipeline / container.

[0050] In a preferred embodiment, defects are detected based on the lag between the determined external temperature profile and the locally averaged external temperature or the temperature of the environment, preferably the air, at or near the pipeline section or vessel, preferably with an increased lag indicating a higher moisture content in the insulation layer.

[0051] The lag can be determined based on a number of features, such as a peak, a valley, a leading leg, a trailing leg, etc.

[0052] Without wishing to be bound by theory, a higher lag in temperature change was observed in situations where the insulation layer had a higher moisture content. This is likely due to the much higher heat capacity of the insulation with a higher moisture content than the dry insulation, causing more heat penetration into the insulation to effectively change the temperature measured at the sensor line in the wet insulation.

[0053] Similarly, in a preferred embodiment, complementing or alternatively to the above, defects are detected based on the temperature difference between the determined external temperature profile and the locally averaged external temperature or environmental, preferably atmospheric, temperature in the pipeline section or vessel, preferably an increased temperature difference indicating a higher moisture content in the insulation layer. Again, without wishing to be bound by theory, higher temperature differences were detected in situations where the insulation layer had a higher moisture content, likely due to increased thermal conductivity of the wet insulation.

[0054] Similarly, preferably in combination with one or more of the above, a correlation was found between the variation over time of the determined external temperature profile and the moisture content of the insulation. As the environmental and / or situation temperature changes, this affects the determined external temperature profile. It was found that for instances where a high moisture content exists in the insulation layer, the variation over time of the determined external temperature profile was much lower than for situations with a lower moisture content. This makes it possible to determine the moisture content in the insulation layer again by comparing the variation of different points on the insulation layer, where comparing adjacent points can provide the most relevant information.

[0055] Similarly, and preferably in combination with one or more of the above, moisture content may be determined by other forms of time series analysis of the determined external temperature profile time series, the locally averaged external temperature profile time series, and / or the environmental temperature time series. Time series analysis methods that may be used include, but are not limited to, cross-correlation, Fourier analysis, autoregressive integrated moving average (ARIMA) modeling, or long short-term memory (LSTM) or other neural networks.

[0056] In a preferred embodiment, a locally averaged external temperature profile is obtained in the monitored insulated pipeline section or the monitored insulated vessel, or between the monitored insulated pipeline section or the monitored insulated vessel and the insulation layer, without optical fiber based temperature sensing and / or distributed temperature sensing.

[0057] In a preferred embodiment, the method comprises the step of evaluating a time series of spatial and temporal variations of the determined temperature profile, taking into account a locally averaged external temperature profile, in order to detect defects.

[0058] In a preferred embodiment, the method includes evaluating the determined temperature profile and a locally averaged external temperature profile via machine learning based anomaly detection.

[0059] In a preferred embodiment, structural data is collected, said structural data including known support points on known locations, a pipeline section or vessel is supported by artificial elements such as brackets, preferably having a thermal conductivity of at least 1 W / (m·K), preferably at least 5 W / (m·K), more preferably at least 10 W / (m·K) at room temperature, and defects are detected based on said structural data. The structural data is preferably provided at the start of the methodology, but may be provided at a later time so that newly added supports can be included over time.

[0060] In particular, the way in which this structural data on known support points is taken into account can be done by excluding zones of the pipeline or container around such locations, as these provide anomalous data. The supports act as thermal bridges, which substantially increase or decrease the temperature determined by the sensor line at these locations, depending on the temperature around the support (air temperature or ground temperature). This is even more so, since at these support points the insulation is often different from that at other points, since it requires a solid connection point, while the insulation at other points is often (more) deformable. To avoid contamination of the measurement data, measurements from points very close to the support point can be completely removed from the results in terms of local averaging. To determine whether the determined temperature profile at said point indicates a defect, it is compared with the locally averaged external temperature profile over a smaller zone, preferably closer to the support point. This reduced zone typically has a radius around said point of at most 2.5 m, or even at most 1.0 m, or even more preferably at most 0.5 m or less. Of course, this too can vary in the specific circumstances.

[0061] In a preferred embodiment environmental data is collected, said data comprising meteorological information including local environmental temperature information, local precipitation information, local solar radiation information, wind information, and said defects are detected taking into account said collected environmental data. In this way, certain deviations can be taken into account, for example an increase in temperature due to insolation, a decrease in temperature due to high winds and / or precipitation, etc. Preferably, this is augmented by structural information about the surroundings, such as its position relative to other structures, so that certain parts may be in shadow and other parts illuminated by the sun, similarly for wind, precipitation, etc.

[0062] In the case of underground pipelines or vessels, one or more additional factors such as soil conditions, soil moisture content, soil type, groundwater flow, etc. are taken into account, while some of the previous factors may potentially be ignored.

[0063] Even more preferably, further information such as hot and / or cold heating, support points, etc. are taken into account as discussed above.

[0064] In a possible embodiment, the spatial distribution of moisture intrusion is evaluated along the length of the pipeline section or along the surface of the insulated vessel being monitored by a second sensor line mounted outside the insulation layer substantially opposite to the first sensor line, and temperature measurements are performed by the second sensor line.

[0065] In a preferred embodiment, an absolute or relative moisture penetration depth into the thermal barrier is calculated for each detected defect based on the determined exterior temperature profile and the locally averaged exterior temperature profile. Based on the measured data, it is possible to estimate the moisture penetration depth.

[0066] The reliability with which the depth can be estimated can be improved over time by a number of methods. First, it is possible to determine a correlation between the determined external temperature profile and the locally averaged external temperature profile on the one hand and the penetration depth on the other hand. This correlation can be further improved over time by the addition of historical data of confirmed defects, which are recorded in the system database. In addition, the database with historical data on confirmed defects can be used, for example, in a machine learning model to provide depth estimates of newly detected defects. Other techniques, such as the use of numerical and / or analytical models, also offer advantages in predicting and characterizing new defects. The estimates can provide an indication of how urgent the problem is and how it will evolve. It should be noted that corrosion only becomes significant when moisture penetration has progressed through the complete insulation layer and reached the pipeline itself. This is particularly useful since changes in moisture penetration depth can be recorded for operations / conditions and effects on changes can be related to said operations / conditions.

[0067] In a preferred embodiment, the predetermined perimeter for determining the local average external temperature profile is at least 0.5 m, preferably at least 1.0 m, more preferably at least 2.5 m, even more preferably at least 5.0 m, and at most 500 m, preferably at most 250 m, more preferably at most 100 m, and even more preferably at most 50 m. In the case of a container, the peripheral surface is within a radius of at least 0.5 m, preferably at least 1.0 m, more preferably at least 2.5 m, and even more preferably at least 5.0 m, and at most 500 m, preferably at most 250 m, more preferably at most 100 m, and even more preferably at most 50 m.

[0068] In the case of a pipeline, the sensor line is installed longitudinally along the pipeline. In the case of a vessel, a more complex positioning is required to adequately cover the vessel's surface. This can be achieved in many ways, but always requires an accurate mapping of the points where the temperature is actually measured to allow averaging within a certain radius.

[0069] In a preferred embodiment, a defect is detected based on a local temperature difference between the determined external temperature profile and the locally averaged external temperature profile. A defect is considered to be detected at a location based on a local temperature difference exceeding a predefined threshold. Said threshold is preferably at least 0.10°C, more preferably at least 0.20°C, even more preferably at least 0.25°C, even more preferably at least 0.30°C, even 0.40°C, 0.50°C or more. The threshold is preferably at most 10.0°C, but more preferably at most 5.0°C, or even 2.5°C, or even 2.00°C, or even 1.50°C, and even 1.0°C or 0.50°C. As mentioned above, a higher difference may indicate a deeper penetration of moisture intrusion into the insulation, and one or more further thresholds may be defined to indicate this, for example with a final threshold indicating that an inspection / repair is urgent, said final threshold being, for example, above 1.0°C.

[0070] In a further aspect, the present invention relates to a system for monitoring moisture intrusion defects above or below ground, comprising a non-underground insulated pipe and an insulated vessel: - a sensor line comprising a single optical fiber or a bundle of optical fibers, which is placed outside the insulation layer along the length of the insulated pipeline section or along the surface of the monitored insulated vessel; - a temperature sensing system, preferably a distributed temperature sensing (DTS) system or a fiber Bragg grating (FBG) temperature sensing system, for determining the external temperature profile over the length of the insulated pipeline section or along the surface of the insulated vessel being monitored; - a data processing unit for detecting defects in the insulated pipeline section or in the insulated container;

[0071] Defects are then detected based on the determined external temperature profile and a locally averaged external temperature profile along the length of the insulated pipeline section or along the surface of the monitored insulated vessel, where the locally averaged external temperature profile is determined for a point by averaging the determined external temperature profile over a predetermined perimeter length or surface for the point.

[0072] In a preferred embodiment, external information is collected, said external information comprising data on external heat / cold sources in the vicinity of the pipeline section or vessel and / or environmental data, said environmental data comprising meteorological information including local environmental temperature information, local precipitation information, local solar radiation information, wind information, said data on external heat / cold sources comprising at least the location of the external heat / cold sources. Defects are then detected together with said external information and the determined external temperature profile and the locally averaged external temperature profile along the length of the insulated pipeline section or along the surface of the insulated vessel being monitored.

[0073] Preferably, the defects are detected according to any of the methods according to the above and / or following embodiments.

[0074] In another aspect the present invention relates to the use of a method according to the first aspect of the invention and / or a system according to the above-mentioned further aspect of the invention for monitoring defects related to moisture ingress in above-ground or underground non-subsea pipeline sections or containers having an insulating layer.

[0075] In an alternative approach, the present invention provides a method for monitoring defects in a pipeline section having an insulation layer, preferably for detecting moisture ingress in the insulation layer, comprising: - installing a sensor line, including a single optical fiber or a bundle of optical fibers, along the length of the insulated pipeline section and positioned outside the insulation layer; - operably coupling the sensor line to a temperature sensing system; - Determination of the external temperature profile over the length of the insulated pipeline section via a temperature sensing system; - detecting defects in an insulated pipeline section, characterized in that defects are detected in the insulated pipeline section, where the defects are detected based on a determined external temperature profile and an assumed internal temperature profile along a length of the insulated pipeline section, where the assumed internal temperature profile is obtained without temperature measurements in the monitored insulated pipeline section or between the monitored insulated pipeline section and the insulation layer.

[0076] It should be noted that the application of the alternative approach to the insulated container, like the first approach, is considered to form part of the present invention, and the method and system variations according to the alternative approach are clear in view of what is described in the first approach.

[0077] Preferably, the temperature sensing system is a distributed temperature sensing (DTS) system. Alternatively, the temperature sensing system is a fiber Bragg grating (FBG) temperature sensing system.

[0078] Preferably, the expected internal temperature profile is obtained without fiber optic based temperature sensing and / or distributed temperature sensing in the monitored insulated pipeline section or between the monitored insulated pipeline section and the insulation layer.

[0079] Preferably, the expected internal temperature profile is determined based on temperature measurements of material in the insulated pipeline sections before and / or after the insulated pipeline section.

[0080] Preferably, defects are detected by comparing the determined external temperature profile with a calculated external temperature profile, the calculated external temperature profile being calculated based on an assumed internal temperature profile and known and / or assumed insulating properties of the insulation layer, said insulating properties preferably including the thermal conductivity of the insulation layer.

[0081] Preferably, defects are detected by comparing an assumed internal temperature profile with a calculated internal temperature profile, the calculated internal temperature profile being calculated based on the determined external temperature profile and known and / or assumed insulating properties of the insulating layer, said insulating properties preferably including the thermal conductivity of the insulating layer.

[0082] Preferably defects are detected by comparing one or more known and / or assumed insulating properties, preferably known and / or assumed thermal conductivity, of the insulating layer with calculated insulating properties, preferably calculated thermal conductivity, of the insulating layer, the calculated insulating properties being calculated based on an assumed internal temperature profile and the determined external temperature profile.

[0083] Preferably, defects are detected based on a known or assumed thermal conductivity and / or a known or assumed thickness of the insulating material along the length of the insulated pipeline section.

[0084] Preferably, the method includes the step of evaluating a time series of spatial and temporal variations of the measured temperature profile, taking into account an assumed internal temperature profile, in order to detect defects.

[0085] Preferably, the method includes evaluating the measured temperature profile and the expected internal temperature profile via machine learning based anomaly detection.

[0086] Preferably, environmental data is collected, said data comprising meteorological information including local environmental temperature information, local precipitation information, local solar radiation information, wind information, and / or information on external heat / cold sources. Faults are detected taking into account said collected environmental data and / or information on external heat / cold sources.

[0087] Preferably the spatial distribution of moisture intrusion is assessed by a second sensor line mounted outside the insulation layer along the length of the pipeline section, substantially opposite to the first sensor line, and temperature measurements are performed by the second sensor line.

[0088] Furthermore, the present invention relates to a system for monitoring defects in an insulated pipe, the system comprising: - a sensor line equipped with a single optical fiber or a bundle of optical fibers and placed outside the insulation layer along the length of the insulated pipeline section; - a temperature sensing system for determining the external temperature profile over the length of the insulated pipeline section, preferably a Distributed Temperature Sensing (DTS) system or a Fiber Bragg Grating (FBG) temperature sensing system; - a data processing unit for detecting defects in an insulated pipeline section, the defects are detected based on a measured external temperature profile and an assumed internal temperature profile along a length of the insulated pipeline section; A data processing unit, characterized in that the assumed internal temperature profile is obtained without temperature measurements on the monitored insulated pipeline section or between the monitored insulated pipeline section and the insulation layer.

[0089] The system is configured to carry out a method according to an alternative approach of the present invention. Furthermore, the invention relates to the use of a method according to the alternative approach of the invention and / or a system according to the alternative approach of the invention for monitoring defects in a pipeline section having an insulating layer.

[0090] In the following, embodiments of the present invention are described. Some appear to be applicable only to the first approach, others to the alternative approach of the present invention, and the rest are applicable to both. Unless otherwise stated, the following embodiments can be applied to both the first approach and the alternative approach of the present invention, as described above.

[0091] An important difference of the present invention compared to the prior art is that in the present invention only one fiber is used (i.e. outside the insulation layer). In contrast to the prior art, the present invention describes how it is sufficient to measure the external pipeline temperature by a DTS or FBG sensing system to detect moisture ingress in the insulation causing CUI. By measuring the temperature outside the insulated pipeline, the zone where moisture ingresses can be detected. To calculate the thermal conductivity of the insulation, a material temperature can be assumed. When the insulation gets wet, the thermal conductivity of the insulation increases and the temperature outside the pipeline insulation becomes more similar to the pipeline temperature. Often, at plant conditions, the temperature of the liquid can be considered constant in the pipeline section. Also, if the material temperature at the inlet and outlet of the pipeline is known, the spatial distribution of the material temperature for the full pipeline can be interpolated.

[0092] It should be noted that an explicit advantage of the present invention is that it can be easily retrofitted to existing (already insulated) pipelines without the need to perform any intrusion operations (removal and reapplication of the insulation layer), since it does not require any actual direct measurement of the pipeline temperature. However, in some situations, the pipeline may already be equipped with temperature sensors at regular intervals. In these cases, as mentioned above, the present invention can be applied very precisely to the pipe sections between these temperature sensors. In most cases, the already available temperature sensors are not present in sufficient numbers to allow a reliable temperature profile that is "perfect" (moisture intrusion may be present in the sections between the temperature sensors, but if these are too far from the intrusion point, this will not be detected), but these can be used to interpolate / extrapolate the assumed temperature profile between them.

[0093] In some embodiments of the present invention, the use of discrete measurement points can be integrated into the concept and can lead to developing a more reliable (i.e., accurate) hypothesized internal temperature profile.

[0094] In most circumstances, the influence of the pipeline itself on the radial temperature profile (perpendicular to the longitudinal axis of the pipeline) in an insulated pipeline is limited. Most pipelines contain metal walls and exhibit excellent heat transfer properties, and it can be expected that the temperature of the material in the pipeline is maintained up to the outer surface of the pipeline and is only substantially reduced by the insulation layer (and the interface between the pipeline and the insulation layer). In this sense, it should be pointed out that the assumed internal profile is typically the temperature profile for the material (in most cases, actual or desired temperatures are available for the material but not for the pipeline), but is essentially equal to the temperature of the pipeline wall. However, in the few cases where the pipeline may have a more significant influence on the thermal conductivity (and the radial temperature profile), this can be taken into account, for example, based on the thermal conductivity of the pipeline and its thickness.

[0095] However, in most embodiments, a spatially / locally averaged external reference temperature is used to compare the measured external temperature. This simplifies the methodology since it requires virtually no knowledge of what is going on inside the pipeline, and at the same time, anomalous measurements can be immediately identified and compensated for.

[0096] Unless otherwise defined, all terms used in disclosing the present invention, including technical and scientific terms, have the meanings commonly understood by those skilled in the art to which the present invention belongs. By way of further guidance, definitions of terms are included to better understand the teachings of the present invention. As used herein, the following terms have the following meanings:

[0097] As used herein, "A," "an," and "the" refer to both singular and plural referents unless the context clearly dictates otherwise. By way of example, "a section" refers to one or more sections.

[0098] "About" as used herein refers to a measurable value such as a parameter, amount, duration, etc., and is meant to encompass variations from the particular value of + / -20% or less, preferably + / -10% or less, more preferably + / -5% or less, even more preferably + / -1% or less, even more preferably + / -0.1% or less, as appropriate for practice in the disclosed invention. However, it should be understood that the value to which the modifier "about" refers is itself specifically disclosed.

[0099] As used herein, "comprise", "comprises", and "comprises" are synonymous with "include", "including", "includes", "includes" or "containing", "containing" or "contains", e.g., the presence of components.

[0100] Moreover, the terms first, second, third, etc. in this specification and claims are used to distinguish between similar elements and are not necessarily used to describe a sequential or chronological order, unless specified. The terms so used are interchangeable under appropriate circumstances, and it is to be understood that the embodiments of the invention described herein are capable of operating in other arrangements than described or illustrated herein.

[0101] The recitation of numerical ranges by endpoints includes all numbers and fractions subsumed within that range, as well as the recited endpoints.

[0102] The terms "fiber optic cable", "optical fiber", "fiber optic cable", or "fiber optic cable" refer to a cable containing one or more optical fibers. The fiber optic elements are typically individually coated with a plastic layer and housed in a protective tube suitable for the environment in which the cable is deployed. The fiber optic cable may be adapted to detect various deformations and intrusions in the pipeline by sensing temperature or other parameters, and may act as a guide to direct the optical signal at one end of the fiber optic cable to another end of the cable.

[0103] The term "outside" refers to everything outside the insulation layer and possibly outside the cladding, if present. The term "measured external temperature profile" refers to the temperature profile measured by a fiber optic cable attached to the outside of the insulation layer. Additionally, the term "expected external temperature profile" refers to the calculated or estimated temperature profile at the location where the external temperature profile is measured. Thus, both are temperature profiles along the length of the pipeline.

[0104] The term "interior" refers to all of the interior of the insulation layer, not including the insulation layer. Typically, this refers to the pipeline itself and its contents (material passing through the pipeline). The term "assumed internal temperature profile" refers to a temperature profile that is calculated / estimated / assumed based on certain assumptions that are independent of the measured external temperature profile, for example based on temperature measurements before and / or after the pipeline section, the intended temperature at which the material should be maintained, etc. The term "calculated internal temperature profile" is a temperature profile calculated using the measured external temperature profile (etc.) where the assumed internal temperature profile is assumed to be applicable. Thus, both are temperature profiles along the length of the pipeline.

[0105] References throughout this specification to "one embodiment" or "embodiment" mean that a particular feature, structure, or characteristic described in connection with the embodiment is included in at least one embodiment of the invention. Thus, the appearances of the phrase "in one embodiment" or "in an embodiment" in various places throughout this specification do not necessarily all refer to the same embodiment, although this may be the case. Furthermore, particular features, structures, or characteristics can be combined in any suitable manner in one or more embodiments, as would be apparent to one of ordinary skill in the art from this disclosure. Furthermore, although some embodiments described herein include some embodiments that are included in other embodiments but do not include other features, combinations of features of different embodiments are meant to be within the scope of the invention and form different embodiments, as would be understood by one of ordinary skill in the art. For example, in the following claims, any of the claimed embodiments can be used in any combination.

[0106] In a first aspect, the invention relates to a fiber optic cable. The fiber optic cable may consist of a single optical fiber or a bundle of fibers (multicore). In this case, other fibers may be used for communication purposes or for other fiber optic sensing and monitoring, such as acoustic or strain sensing. The fiber optic cable may consist of only bare fibers, or of multiple fibers surrounded by multiple coating layers, mantles, strength members, and gels that protect the fibers from mechanical shocks, moisture, hydrogen ingress, and other shocks that may damage the fibers (such cables are widely available in the art). The fibers may also be housed in hollow tubes or microducts, for example, for additional protection or to facilitate installation. The fibers may be standard fibers such as those used in telecommunication applications, or fibers specifically designed for distributed fiber optic sensing or FBG sensing.

[0107] A fiber optic cable is used as a temperature sensor. The temperature is measured along multiple points (which may be discrete or continuous) using fiber optic sensing by connecting the fiber optic cable to a sensing system. Common fiber optic technologies are distributed temperature sensing (DTS) and fiber Bragg grating (FBG). The latter has different forms such as continuous fiber Bragg grating. Most sensor systems have comparable accuracy and resolution. Sensor systems may differ based on spatial resolution, sampling frequency, and the possibility to measure absolute / relative temperature. According to one embodiment, the sensing method used is distributed temperature sensing, including sensing based on Brillouin, Rayleigh, or Raman scattering. In another embodiment, the temperature sensing is based on fiber Bragg grating. In a preferred embodiment, the fiber may be fixed to the cladding using an adhesive tape.

[0108] In further applications, the present invention can be used for anomaly detection by determining hot / cold spots, i.e., the difference between the measurement point and its surrounding points. In some embodiments, for a spot to be recognized as either hot or cold, the difference between the measurement point and its surrounding points must be at least 0.1°C / dm, or preferably 0.5°C / dm, more preferably 1°C / dm, and most preferably 10°C / dm. A significant temperature difference between two points at a difference of 0.1 m is 0.1°C. Of course, this requirement can be used in conjunction with other requirements, such as a minimum difference between measured and calculated / predicted temperatures or calculated and assumed temperatures (or calculated and assumed / known thermal conductivities or other parameters).

[0109] In a further application, the invention detects anomalies via a time series analysis of the received data, taking into account further parameters such as insulation properties, temperature of materials inside the pipeline section, environmental factors (wind, rain) or external heat / cold sources (ii other pipelines). Many of these parameters have a strong correlation with time (e.g., they may be temporal or periodic), and the time series analysis can provide useful insights or detect defects that are only visible temporarily or at certain times.

[0110] In a further application of the present invention, data generated from measurements, calculations, assumptions, and otherwise, can be fed into one or more machine learning models to more accurately and / or quickly identify true defects and filter out false positives. Such machine learning models can be supervised or unsupervised.

[0111] In a further application, the present invention provides data processing, where the fiber temperature sensing system transmits its measurement data to a computer located on-site near the sensing system or at another location, where the data is transmitted via wired or wireless communication. The computer then processes the measurement data and performs fault monitoring and detection. The results of the monitoring are transmitted to a pipeline SCADA (Supervisory Control And Data Acquisition) system or a web-based dashboard.

[0112] The difference in thermal conductivity of the pipeline insulation causes temperature fluctuations on the outside of the insulation. The outside temperature becomes closer to the pipeline temperature. For fluids that are hotter than the environment temperature, this leads to hot spots. For fluids that are colder than the environment temperature, this leads to cold spots. This can be easily detected with a Distributed Temperature Sensing (DTS) or FBG temperature sensing system. The DTS or FBG system measures the temperature along the length of the fiber optic cable. By using a Distributed Temperature or FBG Sensing System compatible fiber cable, the system can be designed to measure temperatures lower than -40°C and higher than 500°C. The proposed system can find moisture ingress of the insulation around the pipeline section.

[0113] Optionally, the data processing unit can be coupled to other data processing units of the installation. In chemical plants, a lot of information is often known about the materials transported in the pipes. Temperature measurements are often made in the reactors. Using data from temperature measurements before and after the insulated pipeline section, assumptions can be made about the internal temperature profile. The spatial distribution of the temperature of the internal materials can be interpolated for the complete pipeline. This information helps the data processing unit to determine the internal temperature profile.

[0114] The detection of defects can be carried out in many non-limiting variants. For example, using the assumed internal temperature (profile) in / on the pipeline itself (usually of material), using the known thermal conductivity of the insulation layer and its thickness (or a combination thereof), the expected external temperature can be calculated and compared with the measured external temperature. Of course, other factors can be used to more accurately determine the expected external temperature (e.g. influence of atmospheric conditions, etc.). If, based on the comparison, the measured and expected external temperatures are different (too strong), a defect can be detected. Alternatively, the inverse can be done and starting from the measured external temperature and the thermal conductivity and thickness of the insulating layer, a predicted internal temperature can be calculated and compared to the assumed internal temperature.

[0115] In a third option, the measured external and assumed internal temperatures and the known thickness of the insulating layer can be used to calculate an expected thermal conductivity, which is then compared to the known conductivity, which may be assumed to be accurate and used to calculate the expected thickness of the insulating layer and to compare with the known thickness.

[0116] Certain thresholds can be established to indicate defects such as differences above a certain percentage, such as at least 1%, preferably at least 2.5%, or even 5.0%, 10%, 20%, 30%, 40%, or even 50%. However, lower difference thresholds are preferred to find defects in a timely manner. In some embodiments, the threshold is set at a difference of at least 75%. The difference can be set in absolute value, especially for temperature differences such as 1°C, preferably at least 2.5°C, or even 5°C, 10°C, 20°C, but also for other parameters such as differences in thermal conductivity, with thresholds of at least 0.001 W / (m·K), preferably at least 0.001 W / (m·K), or even 0.005 W / (m·K), 0.010 W / (m·K). Lower thresholds are also preferred, as they allow for higher sensitivity and a more proactive style of monitoring.

[0117] Wet insulation causes an increase in the adiabatic conductivity above a certain threshold. Achtziger, J., JCammerer 1984: 'Water Content versus Thermal conductivity', (Einfluss des Feuchtegehaltes auf die Warmeleitfahigkeit von Bauund Dammstoffen), FIW Munchen.

[0118] In order to be able to detect moisture in the insulation, in the case of wet insulation, the temperature measured on the outside of the pipeline should be different from the surrounding environment temperature. The pipeline type is not important, nor is the insulation type. What is important is that the heat / cold transfer of the pipeline through the wet insulation is large enough to be detected. The difference between the measured temperature on the outside of the pipeline and the surrounding external temperature needs to be larger than the measurement accuracy of the DTS or FBG system (usually 0.5°C).

[0119] As stated by Raudensky et al. (Impact of oxide scale on heat treatment of steels, 2014), corrosion of metals also causes a change in thermal conductivity. This change in total thermal conductivity causes a change in the temperature measured on the exterior of the insulated pipeline. Depending on the temperature, corrosion of metal pipelines can cause an increase or decrease in thermal conductivity. Thus, corrosion is more easily observed when the temperature of the material in the pipeline section fluctuates. Furthermore, the amount of moisture inside the insulation layer is in some circumstances not constant over time, leading to changes in the DTS / FBG temperature. Thus, corrosion of metal pipeline sections can be detected based on the measured data, even if the intrusion of moisture is temporary (or cyclical). Even the severity of the corrosion can be determined based on said data. To make these observations, accurate temperature measurements are necessary. This system prevents corrosion, but also allows the observation of corrosion that may have formed before installation. The advantage of the present invention allows continuous monitoring of the pipeline, thereby overcoming also temporary or cyclical problems. The effects of such effects may in some cases only become apparent if monitored over a long period of time (e.g. initial moisture intrusion increases thermal conductivity due to degradation of the insulation layer, and later decreases thermal conductivity due to corrosion forming a layer on the metal pipeline that has - relatively - low thermal conductivity).

[0120] The fiber optic sensing cable detects and measures the temperature along the radially outer region of the insulation layer. When 1 vol.% water is added, the efficiency of the insulation layer in the wetted region is reduced such that the temperature along the length of the insulated pipe may increase by nearly 30°C compared to a pipeline section with dry insulation. The temperature increase caused by the reduction in insulation efficiency can be easily detected and measured by the fiber optic sensing cable in the wetted region along the insulated piping.

[0121] Once a change in temperature is detected by the system, the system can provide an audible and / or visual output for review by an operator. The precise location of the temperature change allows an operator to inspect and test the specific area of ​​the insulated vessel potentially experiencing a problem. An operator, such as a plant operator, can evaluate the specific area or areas to determine if any area of ​​the insulation has actually become wet. Depending on the degree and location of the intruding moisture, appropriate corrective action can be taken to reduce or eliminate moisture intrusion and potential corrosion under the insulation.

[0122] To be able to measure the temperature outside the pipeline, the fiber needs to be in intimate contact with the pipeline jacket. One possible way to ensure this intimate contact is by taping the fiber with a special tape in close contact with the jacket. In this case it can be beneficial for the fiber to have a small diameter (<2mm). Another possibility is to place the fibers under the jacket or inside the insulation, but this is less efficient and easier to install.

[0123] The methods and systems for detecting corrosion are also applicable to other insulated vessels such as reactors, tanks and other assets.

[0124] Early detection of corrosion or other damage in a pipeline can, for example, reduce maintenance and repair times by facilitating early intervention. Thus, real-time monitoring techniques that can monitor a pipeline segment or the entire length of the pipeline using fiber optic cable can aid in early detection. As described above, the monitoring system can continue to utilize the fiber optic cable to monitor pipeline wall thickness and pipeline corrosion, erosion, or failure even if a portion of the fiber optic cable is damaged. Such can be uniquely facilitated, for example, by using multiple light sources and receivers along the fiber optic cable. If a portion of the fiber optic cable is damaged, the remaining undamaged portion of the fiber optic cable can continue to be utilized to sense and collect data.

[0125] Applicant unexpectedly observed that if the material temperature is unknown and not constant, the material temperature does not need to be known to detect moisture ingress in the insulation. Due to insulation, the temperature of the material does not change over short distances. Temperature anomalies measured on the outside of an insulated pipeline are caused by insulation properties, environmental factors (wind, rain, etc.), or external heat / cold sources (other pipelines, etc.). Moisture ingress in insulation is mostly localized and has a temporal component, e.g., dry / wet cycles. Due to these typical spatial and temporal characteristics of moisture ingress compared to other causes of temperature anomalies, moisture ingress can be identified by advanced time series analysis and / or machine learning.

[0126] This technology has extremely low installation overhead requirements, with minimal power cabling required, and signal transmission via the fiber optic sensing cable. The present invention achieves the above objectives with a single fiber optic cable permanently attached to the outside of the pipeline insulation. No second fiber optic cable is required inside the pipe or insulation, since the internal temperature profile is assumed based on other known parameters. The advantages of using only one fiber are: This allows for easy installation, especially when retrofitting old or already insulated pipelines, as the insulation and cladding do not need to be removed to install the fibres. -The anomalous results cannot be masked by mirrored variations (in this case the temperature results vary to a similar extent in both fibers). - The assumption of a "known" temperature in the pipeline allows for a simplified determination of thermal conductivity and / or insulation properties -Errors in pipeline temperature measurement are avoided.

[0127] In another preferred embodiment, the optical fiber sensor is installed inside the cladding, with the preferred location of the fiber on the outside of the pipeline jacket being at the lowest point of the pipeline cross section to avoid damage to the fiber due to gravity and to minimize local temperature variations due to solar radiation.

[0128] In another preferred embodiment, the optical fiber is placed in intimate contact with the cladding using adhesive tape. Other embodiments use glue, tie wraps, or magnetic tape, magnets, or other methods of attaching the fiber.

[0129] In another embodiment, a second sensor line is installed along the length of the pipeline, on the outside of the insulation layer, opposite the first sensor line. Similarly, relative to the first sensor line, the second sensor line performs temperature measurements. This additional data set gives more information regarding the size and location of the moisture intrusion within the insulation. This allows for more precise localization of the moisture intrusion. [Explanation of symbols]

[0130] 101 Pipeline 102 Substance 103 Insulation 104 Clad 105 Fiber optic cable

Claims

1. 1. A method for monitoring defects in a surface or underground non-subsea pipeline section or vessel having an insulation layer, the defects being related to moisture ingress in said insulation layer, comprising the steps of: - placing a sensor line, comprising a single optical fiber or a bundle of optical fibers, along the length of the insulated pipeline section or along the surface of the insulated vessel, outside the insulation layer; - operatively coupling the sensor line to a temperature sensing system; - determining the external temperature profile over the length of the insulated pipeline section or over the surface of the insulated vessel via a temperature sensing system; - detecting defects on the surface of an insulated pipeline section or an insulated container A method comprising: external information is collected, the external information including data and / or environmental data relating to an external heat / cold source in the vicinity of the pipeline section or container, the environmental data including meteorological information including local environmental temperature information, local precipitation information, local solar radiation information, wind information, the data relating to the external heat / cold source including at least a location of the external heat / cold source; and the defect is detected based on the external information, a determined external temperature profile and a locally averaged external temperature profile along the length of the insulated pipeline section or over a surface of an insulated vessel, the locally averaged external temperature profile being determined for a point by averaging the determined external temperature profile over a predetermined perimeter or surface for the point. method.

2. 2. The method of claim 1, wherein the defect is detected based on the determined external temperature profile over a predetermined period of time, preferably based on a time-averaged difference between the locally averaged external temperature profile and the determined external temperature profile over the predetermined period of time, the predetermined period of time being preferably at least 5 minutes, more preferably at least 1 hour, even more preferably at least 1 day, and most preferably at least 1 week.

3. 3. The method of claim 2, wherein the time-averaged difference excludes or associates a reduced weighting to the predetermined external temperature profile during the predetermined time period, during which the predetermined external temperature profile differs from a reference temperature profile by less than a predetermined delta value, preferably at least 0.10°C, more preferably at least 0.25°C, and wherein the reference temperature profile is preferably the environmental, preferably atmospheric, temperature in the vicinity of the pipeline section or vessel.

4. A method as claimed in claim 2 and preferably as claimed in claim 3, wherein the time difference is determined based on one or more of the following: time, season, wind conditions, other weather conditions, pipeline or container usage parameters; eliminating or relating reduced weight to a given external temperature profile during the given period; the time difference is determined based on any one or more of the following:

5. The method according to any one of claims 1 to 4, wherein the temperature sensing system is a distributed temperature sensing (DTS) system.

6. The method according to any one of claims 1 to 4, wherein the temperature sensing system is a Fiber Bragg Grating (FBG) temperature sensing system.

7. 7. The method according to any one of claims 1 to 6, wherein the locally averaged external temperature profile is obtained without optical fiber based temperature sensing and / or distributed temperature sensing in the monitored insulated pipeline section or the monitored insulated vessel, or between the monitored insulated pipeline section or the monitored insulated vessel and the insulation layer.

8. A method according to any one of claims 1 to 7, wherein the locally averaged external temperature profile at each point is the median temperature over the defined perimeter or surface of the point.

9. A method according to any one of claims 1 to 7, wherein the defects are detected taking into account known and / or assumed insulating properties of the insulation layer, said insulating properties preferably comprising the thermal conductivity of the insulation layer.

10. The method according to any one of claims 1 to 9, wherein the method is for monitoring defects in an above-ground pipeline section.

11. A method according to any one of claims 1 to 10, wherein the defects are detected based on a delay between the determined external temperature profile and the locally averaged external temperature or environment, preferably ambient temperature, at or near the pipeline section or vessel, preferably an increased delay indicating a higher moisture content in the insulation layer.

12. A method according to any one of claims 1 to 10, wherein the defects are detected based on a temperature difference between the determined external temperature profile and the locally averaged external temperature or environment, preferably ambient temperature, at or near the pipeline section or vessel, preferably an increase in the temperature difference being indicative of a higher moisture content in the insulation layer.

13. A method according to any one of the preceding claims, wherein the defects are detected further based on the temperature of a known or assumed environment, preferably the air, at or near the pipeline section or vessel.

14. 14. The method according to claim 1, comprising evaluating time series spatial and temporal variations in the determined temperature profile taking into account the locally averaged external temperature profile to detect defects.

15. 15. The method of any one of claims 1 to 14, comprising evaluating the determined temperature profile and a locally averaged external temperature profile via machine learning based anomaly detection.

16. 16. The method according to any one of claims 1 to 15, wherein structural data is collected, said structural data comprising known support points at known locations, said pipeline section or vessel being supported by artificial elements having a thermal conductivity at room temperature of preferably at least 5 W / (m·K), preferably at least 10 W / (m·K), and said defects being detected based on said structural data.

17. The external information includes environmental data, the data including local environmental temperature information, local precipitation information, local solar radiation information, and weather information; The defects are detected in consideration of the collected environmental data; A method according to any one of the preceding claims 1 to 16.

18. 18. The method according to any one of claims 1 to 17, wherein the spatial distribution of the moisture intrusion is assessed along the length of the pipeline section or along the surface of the monitored insulated vessel by a second sensor line attached outside the insulation layer, substantially opposite to the first sensor line, and temperature measurements are performed by the second sensor line.

19. 19. The method according to any one of claims 1 to 18, wherein an absolute or relative penetration depth of moisture into the insulation layer is calculated for each detected defect based on the determined external temperature profile and the locally averaged external temperature profile.

20. 20. A method according to any one of claims 1 to 19, wherein the predetermined perimeter is at least 0.5m, preferably at least 1.0m, more preferably at least 2.5m, even more preferably at least 5.0m, and at most 500m, preferably at most 250m, more preferably at most 100m, and even more preferably at most 50m; or wherein the peripheral surface is within a radius of at least 0.5m, preferably at least 1.0m, more preferably at least 2.5m, and even more preferably at least 5.0m, and at most 500m, preferably at most 250m, more preferably at most 100m, and even more preferably at most 50m.

21. The method according to any one of the preceding claims, wherein the defects are detected based on a local temperature difference between the determined external temperature profile and the locally averaged external temperature profile.

22. 1. A system for monitoring defects related to moisture ingress in above-ground or below-ground, other than subsea, insulated pipes and insulated containers, comprising: - a sensor line consisting of a single optical fiber or a bundle of optical fibers placed outside the insulating layer along the length of the insulated pipeline section or along the surface of the insulating vessel to be monitored; - a temperature sensing system for determining the external temperature profile over the entire length of the insulated pipeline section or along the surface of the insulated container being monitored, preferably a distributed temperature sensing (DTS) system or a fiber Bragg grating (FBG) temperature sensing system; - a data processing unit for detecting defects in the insulated pipeline section or in the insulated container; Including, external information is collected, the external information including data and / or environmental data relating to an external heat / cold source in the vicinity of the pipeline section or container, the environmental data including meteorological information including local environmental temperature information, local precipitation information, local solar radiation information, wind information, the data relating to the external heat / cold source including at least a location of the external heat / cold source; and the defect is detected based on the external information, a determined external temperature profile and a locally averaged external temperature profile along a length of the insulated pipeline section or over a surface of an insulated vessel, the locally averaged external temperature profile being determined for a point by averaging the determined external temperature profile over a predetermined perimeter or surface for the point; The defect is detected by a method according to any one of claims 1 to 21. system.

23. Use of the method according to any one of claims 1 to 21 or the system according to claim 22 for monitoring defects related to moisture ingress in above-ground or underground, non-subsea pipeline sections or vessels having an insulating layer.

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