Detecting subsea pipe deposition using acoustic measurements

Abstract

A system includes an acoustic measurement device configured for subsea use, a processor configured to be communicatively coupled to the acoustic measurement device, and a memory communicatively coupled to the processor. The acoustic measurement device includes at least one hydrophone to measure acoustic signals from a subsea location and a frame coupled to the hydrophone and configured to position the hydrophone proximate a subsea conduit. The memory stores instructions that, when executed by the processor, cause the processor to receive, from the acoustic measurement device, an output indicative of acoustic signals measured by the hydrophone; determine at least one acoustic property of the subsea conduit based on the output; identify a deposit present inside the subsea conduit based on the at least one acoustic property; and estimate one or more physical properties of the deposit within the subsea conduit based on the at least one acoustic property.

Description

DETECTING SUBSEA PIPE DEPOSITION USING ACOUSTIC MEASUREMENTSCROSS REFERENCE TO RELATED APPLICATIONS

[0001] This is a PCT patent application claiming the benefit of U.S. Provisional Patent Application No. 63 / 634,779, filed on April 16, 2024, which is hereby incorporated by reference in its entirety and for all purposes.TECHNICAL FIELD

[0002] The present invention is directed to methods and devices for detecting material deposition in subsea pipes, and more particularly, to acoustic measurement systems and methods for monitoring and detecting the extent of material deposition inside subsea pipes.BACKGROUND

[0003] In the activity of transporting produced oil and gas via a pipeline, deposits may accumulate on the internal surfaces of the pipeline. Over time, the deposition of materials (e.g., wax, gel, sand, inorganic scale, asphaltene, and / or hydrate) may hinder flow or completely block the flow path through the pipeline. Deposits may develop over a short period (e.g., unintended production of sand could impact production within hours) or over a longer period (e.g., the impact of gradual wax deposition may be undetectable for months).

[0004] Monitoring the internal state of the pipeline involves the measurement of key parameters (e.g., pressures, temperatures, flow rates) and observing the progression of measured values in time. Monitoring is performed to identify conditions that may hinder production. Detection involves determining the location of a deposit that is hindering production.

[0005] Few methods exist for monitoring and detecting the extent of deposition within offshore oil and gas production lines. Of the conventional methods of interrogating the internal state of a pipeline, pigging operations are the most used method for purging, cleaning, and inspecting pipelines. In a typical pigging operation, a physical device is placed within the pipe of interest. The mechanical device is designed to maintain a seal with the pipe wall and is forced through the pipe by a difference in fluid pressure. Unfortunately, in pigging operations, mechanical devices can stop moving or become stuck in the pipeline. Stopped or stuck devices will block the flow path and must be removed from the pipeline before flow may resume.

[0006] Alternatively, external devices may be used to detect the internal state of the pipeline. For example, computed tomographic (CT) imaging has been used to detect deposits in pipelines in cases where the density differences between deposit and surrounding materials (e.g., variousphases of fluid or pipe wall) are significant enough to enable the detection of these differences in pipeline. However, CT devices are normally transported to a location where deposition is suspected, and images of pipeline cross-sections are created by moving the CT device from one location to another. This is a time intensive and costly process.BRIEF DESCRIPTION OF THE DRAWINGS

[0007] The drawings illustrate only example embodiments and are therefore not to be considered limiting in scope, as the example embodiments may admit to other equally effective embodiments. The elements and features shown in the drawings are not necessarily to scale, emphasis instead being placed upon clearly illustrating the principles of the example embodiments. Additionally, certain dimensions or positions may be exaggerated to help visually convey such principles.

[0008] FIG. I is a schematic view of a system in which deposition detection devices are installed along a subsea conduit, in accordance with an embodiment of the present disclosure.

[0009] FIG. 2 is a schematic diagram illustrating the main components of a deposition detection system, in accordance with an embodiment of the present disclosure.

[0010] FIG. 3 is a schematic diagram illustrating another deposition detection system, in accordance with an embodiment of the present disclosure.

[0011] FIGS. 4A and 4B are front and side partial cross-sectional views illustrating an acoustic measurement device, in accordance with an embodiment of the present disclosure.

[0012] FIG. 5 is a front partial cross-sectional view of an acoustic measurement device with an array of hydrophones, in accordance with an embodiment of the present disclosure.

[0013] FIG. 6 is a perspective view of a jumper and multiple monitoring locations along the axial length of the jumper, in accordance with an embodiment of the present disclosure.

[0014] FIG. 7 is a process flow diagram illustrating a method for detecting material deposition inside a subsea conduit, in accordance with an embodiment of the present disclosure.

[0015] FIGS. 8A and 8B are side partial cross-sectional views of test setups for an acoustic measurement device, in accordance with an embodiment of the present disclosure.

[0016] FIG. 9 is a top partial cross-sectional view of the test setup of FIG. 8B, in accordance with an embodiment of the present disclosure.

[0017] FIG. 10 is a spectrogram of a sound recording taken via an acoustic measurement device, in accordance with an embodiment of the present disclosure.

[0018] FIG. 11 is a plot illustrating a sound recording taken via an acoustic measurement device, in accordance with an embodiment of the present disclosure.

[0019] FIG. 12 is a plot illustrating frequency responses determined from acoustic measurements for multiple angular locations around a pipe segment without alginate, in accordance with an embodiment of the present disclosure.

[0020] FIGS. 13 A and 13B are plots illustrating frequency responses determined from acoustic measurements for multiple angular locations around a pipe segment with alginate, in accordance with an embodiment of the present disclosure.

[0021] FIG. 14 is a plot illustrating a comparison between frequency responses from acoustic measurements taken around a pipe segment with alginate and without alginate, in accordance with an embodiment of the present disclosure.

[0022] FIGS. 15A-15H are polar plots comparing the frequency responses of baseline acoustic measurements from FIG. 12 with alginate-impacted acoustic measurements from FIGS. 13A and 13B, in accordance with an embodiment of the present disclosure.

[0023] FIG. 16 is a plot illustrating pressure vs. frequency for acoustic responses around a pipe segment with alginate and without alginate according to modeling, in accordance with an embodiment of the present disclosure.

[0024] FIG. 17 is a polar plot illustrating the average frequency response of acoustic modeling for a pipe segment with alginate and without alginate, in accordance with an embodiment of the present disclosure.DETAILED DESCRIPTION OF THE DRAWINGS

[0025] The example embodiments discussed herein are directed to systems, apparatus, and methods related to monitoring and detecting depositions (e.g., wax or other materials) inside subsea pipelines. In particular, the disclosed systems, apparatus, and methods provide a low-cost method of detecting wax or other material deposition using an acoustic measurement device placed external to a pipeline. The device measures acoustic signals from outside of the pipeline, and the measured signals are then analyzed to monitor and detect the internal state of the pipeline. The disclosed systems, apparatus, and methods enable both monitoring (i.e., observing the progression of deposition) and detection (i.e., determining the location of a deposit) of the internal state of the pipeline. The terms “conduit,” “pipeline” and “pipe” are used herein interchangeably and may refer to a subsea pipeline or a subsea jumper. A subsea pipeline may include a trench crossing pipeline.

[0026] The use of the terms "about", “approximately”, and similar terms applies to all numeric values, whether or not explicitly indicated. These terms generally refer to a range of numbers that one of ordinary skill in the art would consider as a reasonable amount of deviation to the recitednumeric values (i.e., having the equivalent function or result). For example, this term may be construed as including a deviation of ±10 percent of the given numeric value provided such a deviation does not alter the end function or result of the value. Therefore, a value of about 1% may be construed to be a range from 0.9% to 1.1%. Furthermore, a range may be construed to include the start and the end of the range. For example, a range of 10% to 20% (i.e., range of 10%-20%) includes 10% and also includes 20%, and includes percentages in between 10% and 20%, unless explicitly stated otherwise herein. Similarly, a range of between 10% and 20% (i.e., range between 10% - 20%) includes 10% and also includes 20%, and includes percentages in between 10% and 20%, unless explicitly stated otherwise herein.

[0027] It is understood that when combinations, subsets, groups, etc. of elements are disclosed (e.g., combinations of components in a composition, or combinations of steps in a method), that while specific reference of each of the various individual and collective combinations and permutations of these elements may not be explicitly disclosed, each is specifically contemplated and described herein. By way of example, if an item is described herein as including a component of type A, a component of type B, a component of type C, or any combination thereof, it is understood that this phrase describes all of the various individual and collective combinations and permutations of these components. For example, in some embodiments, the item described by this phrase could include only a component of type A. In some embodiments, the item described by this phrase could include only a component of type B. In some embodiments, the item described by this phrase could include only a component of type C. In some embodiments, the item described by this phrase could include a component of type A and a component of type B. In some embodiments, the item described by this phrase could include a component of type A and a component of type C. In some embodiments, the item described by this phrase could include a component of type B and a component of type C. In some embodiments, the item described by this phrase could include a component of type A, a component of type B, and a component of type C. In some embodiments, the item described by this phrase could include two or more components of type A (e.g., Al and A2). In some embodiments, the item described by this phrase could include two or more components of type B (e.g., Bl and B2). In some embodiments, the item described by this phrase could include two or more components of type C (e.g., Cl and C2). In some embodiments, the item described by this phrase could include two or more of a first component (e.g., two or more components of type A (Al and A2)), optionally one or more of a second component (e.g., optionally one or more components of type B), and optionally one or more of a third component (e.g., optionally one or more components of type C). In some embodiments, the item described by this phrase could include two or more of a first component (e.g., two or morecomponents of type B (B 1 and B2)), optionally one or more of a second component (e.g., optionally one or more components of type A), and optionally one or more of a third component (e.g., optionally one or more components of type C). In some embodiments, the item described by this phrase could include two or more of a first component (e.g., two or more components of type C (Cl and C2)), optionally one or more of a second component (e.g., optionally one or more components of type A), and optionally one or more of a third component (e.g., optionally one or more components of type B).

[0028] If a component of a figure is described but not expressly shown or labeled in that figure, the label used for a corresponding component in another figure may be inferred to that component. Conversely, if a component in a figure is labeled but not described, the description for such component may be substantially the same as the description for the corresponding component in another figure. For any figure shown and described herein, one or more of the components may be omitted, added, repeated, and / or substituted. Accordingly, embodiments shown in a particular figure should not be considered limited to the specific arrangements of components shown in such figure.

[0029] Further, a statement that a particular embodiment (e.g., as shown in a figure herein) does not have a particular feature or component does not mean, unless expressly stated, that such embodiment is not capable of having such feature or component. For example, for purposes of present or future claims herein, a feature or component that is described as not being included in an example embodiment shown in one or more particular drawings is capable of being included in one or more claims that correspond to such one or more particular drawings herein.

[0030] Terms such as “first”, “second”, “primary,” “secondary,” “above”, “below”, “inner”, “outer”, “distal”, “proximal”, “end”, “top”, “bottom”, “upper”, “lower”, “side”, “left”, “right”, “front”, “rear”, and “within”, when present, are used merely to distinguish one component (or part of a component or state of a component) from another. This list of terms is not exclusive. Such terms are not meant to denote a preference or a particular orientation, and they are not meant to limit embodiments of earth penetrating tools. In the following detailed description of the example embodiments, numerous specific details are set forth in order to provide a more thorough understanding of the invention. However, it will be apparent to one of ordinary skill in the art that the invention may be practiced without these specific details. In other instances, well-known features have not been described in detail to avoid unnecessarily complicating the description.

[0031] FIG. 1 schematically illustrates a system in which at least one acoustic measurement device 100 is located subsea, proximate a subsea conduit 102. The subsea conduit 102 may be located on the seabed or above the seabed. Three acoustic measurement devices 100 are installedin the pipeline system shown. The illustrated system further includes a pipeline end termination (PLET) 104. The acoustic measurement devices 100 may be positioned against a wall 106 of the subsea conduit 102 or offset a certain distance from the wall of the subsea conduit 102. In some embodiments, one or more acoustic measurement devices 100 may be coupled to or integrated into a remote operated vehicle (ROV) 108 deployed subsea to a location proximate the subsea conduit 102, as shown. In some embodiments, an ROV 108 (with or without acoustic measurement devices 100 incorporated thereon) may periodically interface with the acoustic measurement devices 100 located proximate the subsea conduit 102 to collect measurements from the devices for processing and / or communication to a topside location, and / or to recharge a power supply of the acoustic measurement device 100.

[0032] As discussed in further detail below with reference to FIG. 2, each acoustic measurement device 100 may include one or more hydrophones configured to measure acoustic signals from a subsea location (i.e., proximate the subsea conduit 102). In accordance with present techniques, the acoustic measurements provided by the hydrophone(s) are then used to determine 1) whether a deposit is present inside the subsea conduit 102 and 2) if so, the location of the deposit within the subsea conduit 102.

[0033] Various acoustic properties of the subsea conduit 102 may be impacted by an internal pipeline deposit layer (e.g., wax, gel, scale, asphaltene, hydrate, or sand deposit inside the conduit). Deposits will increase the effective total thickness of the subsea conduit inner wall and decrease the fluid flowpath through the conduit 102. As such, deposit accumulation within the subsea conduit 102 introduces three distinct changes to observable acoustic properties in the subsea conduit 102.

[0034] First, the deposit(s) may affect the level of sound output from the subsea conduit 102. The deposit(s) accumulated on the inner walls of the subsea conduit 102 have good sound and temperature insulation properties. As such, changing the effective thickness and mass of the wall (e.g., the thickness / mass of the wall of the subsea conduit 102 plus the thickness / mass of any deposit formed on the wall) changes the sound level of fluid flowing through the subsea conduit 102 due to changes in sound damping from the subsea conduit 102. As such, measuring sound from outside of the subsea conduit 102 can provide an indication of the change in thickness / mass of the wall due to the formation of wax or other deposits in the subsea conduit 102.

[0035] Second, the deposit(s) may affect the frequency of sound output from the subsea conduit 102. The speed of fluid flowing through the subsea conduit 102 is affected by wax or other deposit accumulation, as the accumulation of deposits causes a constricted flow cross-section within the subsea conduit 102. The changing speed of fluid flowing through the subsea conduit 102 maychange the sound (particularly sound frequency) from fluid flowing through the subsea conduit 102. As such, measuring sound from outside of the subsea conduit 102 may provide an indication of the change in speed of fluid flowing through the subsea conduit 102 due to the formation of wax or other deposits in the subsea conduit 102.

[0036] Third, the deposit(s) may affect the natural frequency of the subsea conduit 102. The natural frequency of a segment of the subsea conduit 102 supported at two points decreases as wax or other deposits accumulate in the subsea conduit 102. Changing the effective thickness and mass of the wall of the subsea conduit 102 via deposits changes the harmonics of that segment of the subsea conduit 102. As such, measuring natural frequency of a segment of the subsea conduit 102 may provide an indication of the change in effective thickness and mass of the wall due to the formation of wax or other deposits in the subsea conduit 102.

[0037] The acoustic measurement device(s) 100 may be used to capture and measure the above listed observable property changes caused by the accumulation of deposits in the subsea conduit 102. The acoustic measurement device(s) 100 may collect acoustic data that will be analyzed in the time and frequency domains to identify one or more acoustic properties such as flow sound magnitude, flow sound frequency, and the natural frequency of the subsea conduit 102 at a known production rate. The trend in these three properties correlates to material deposition in the subsea conduit 102. Flow sound magnitude may be in decibels, and a decrease in decibels of the sound measured by the acoustic measurement device 100 may indicate a deposit. Flow sound frequency may refer to the dominant frequencies of the measured sound (e.g., combinations of frequencies above 3 kHz), and an increase of the frequency of sound measured may indicate a deposit. Natural frequency of the subsea conduit 102 may be the frequency at which the subsea conduit 102 vibrates (e.g., less than 100 Hz tonal peak frequency), and a change in the natural frequency may indicate a deposit. In some embodiments, the acoustic data collected by the acoustic measurement device(s) 100 may also be analyzed for detection of any leaks from the subsea conduit 102.

[0038] While the acoustic measurement device(s) 100 may provide measurements used to determine natural frequency of a segment of the subsea conduit 102, in certain embodiments an acceleration measurement may be used to determine and / or validate the natural frequency of a segment of the subsea conduit 102. For example, the acoustic measurement device 100 may include or may be communicatively coupled to an accelerometer that is coupled to an external wall 106 of the subsea conduit 102 to obtain these measurements.

[0039] Each hydrophone used in an acoustic measurement device 100 may measure a full spectrum of sound, for example, from 2 Hz to 200 kHz. In other embodiments, the hydrophone may measure a more limited spectrum of sound. For example, the hydrophone may measure soundin the frequency range of about 10 kHz to 50 kHz. In some embodiments, the processing of the acoustic measurements taken by the acoustic measurement device(s) 100 may include filtering the measurements to include only the sound measurements in the frequency range of about 10 kHz to 50 kHz. This is because at a frequency less than 10 kHz the signal -to-noise ratio is too low to interpret, while at a frequency of greater than 50 kHz the subsea conduit 102 is generally not vibrating. The range of targeted sound frequencies may shift, though, depending on the hardness of wax or other deposits that may build up in the subsea conduit 102. For example, the frequency range of investigation would likely be different for detecting sand deposits, as opposed to wax deposits.

[0040] In some embodiments, the system may include sensors configured to measure one or more production flow properties, such as flow rate of fluid flowing through the subsea conduit 102. Such sensors may be located at a subsea location (e.g., at a PLET 104) or at a topside location that is fluidly coupled to the subsea conduit 102. For long pipelines, the flow rate of fluid through the subsea conduit 102 may change throughout the day. As such, it may be desirable to incorporate the changes in flow rate through the subsea conduit 102 with changes in acoustic properties measured at different times of day via the acoustic measurement devices 100. These measurements may be used to determine a baseline pattern of acoustic measurements and flow rate over time prior to performing the monitoring and detecting of deposits in the subsea conduit 102.

[0041] The acoustic measurement device(s) 100 may be battery powered. A battery powered acoustic measurement device 100 may be able to capture sound and vibrations for months when operated intermittently, or for about 10 to 20 hours when operated continuously. Acoustic measurement device(s) 100 that are incorporated into an ROV 108 may use the ROV power source and may be able to capture sound and vibrations for about 3 to 5 hours when operated continuously. In some embodiments, one or more acoustic measurement devices 100 may be deployed subsea in the form of a data collection unit with a subsea power line 110, enabling continuous measurements for longer periods of time.

[0042] The acoustic imaging system and method may utilize either active (generated) sources or passive (natural) sources of vibration, noise, tones, or sounds when taking acoustic measurements to determine an indication of deposit absence or presence. In some embodiments, the system may include an active sound source 112 deployed subsea proximate the subsea conduit 102. The active sound source 112 may be in contact with the subsea conduit 102, incorporated into the acoustic measurement device 100, or otherwise located close to the subsea conduit 102. The active sound source 112 may generate sound and / or vibrations at the subsea conduit 102. For example, the active sound source 112 may include a speaker or other component configured tooutput acoustic signals to the subsea conduit 102. As another example, the active sound source 112 may include a mechanism configured to periodically strike the subsea conduit 102 to vibrate the conduit. The hydrophone(s) on the acoustic measurement device(s) 100 located proximate the subsea conduit 102 may measure acoustic signals resulting from the active sound source 112 acting on the subsea conduit 102.

[0043] In some embodiments, the hydrophone(s) on the acoustic measurement device(s) 100 located proximate the subsea conduit 102 may measure acoustic signals resulting from a passive source of noise or vibration (e.g., noise or vibrations occurring naturally due to regular operations of the subsea conduit 102). The naturally occurring noise may be noise from the flow of fluid through the subsea conduit 102, flow of fluid through a choke, and other sounds caused by subsea production.

[0044] As illustrated, multiple acoustic measurement devices 100 may be used to detect the sound, noise, and / or vibrations over time and over a span of locations (e.g., circumferential and / or axial locations) along the subsea conduit 102 to identify deposit absence or presence and / or to detect the extent of deposition in the conduit 102. Further, this method may be used to measure deposit characteristics (e.g., distribution in axial direction, distribution in circumferential direction, relative shape of deposit, estimated thickness or mass of deposit, etc.). The measurements may enable quantitative or qualitative analysis of deposit characteristics.

[0045] A single sensor (i.e., hydrophone of the acoustic measurement device 100) or multiple sensors may be placed near the conduit wall 106. The sensor(s) may be placed at different axial locations along the subsea conduit 102 in a manner to enable axial detection of a deposit, as shown by the multiple measurement devices 100 in FIG. 1. Additionally, or alternatively, the sensor(s) may be placed at different circumferential locations along the subsea conduit 102 in a manner to enable circumferential detection of a deposit. One example of this circumferential detection is shown in FIG. 4.

[0046] Acoustic signals measured by the acoustic measurement device 100 may be stored in a memory of the device 100 for later retrieval to a surface location for analysis. In some embodiments, acoustic signals measured by the device 100 may be communicated to a passing device (e.g., an ROV 108 interfacing with the acoustic measurement device 100), a permanently installed subsea processor, or a topside location (e.g., via a subsea communication line).

[0047] A processor may determine one or more acoustic properties (e.g., sound level, sound frequency, and / or natural frequency of conduit 102) for the section of conduit based on the data received from each measurement device 100. A change in the one or more acoustic properties from an expected value at a single position can be translated to a relative thickness of a deposit at thatposition. The expected signal value may be obtained from an analysis of historical data, simulation, or analogs.

[0048] Multiple acoustic detection devices 100 may be used to improve the resolution of the detection method. In some embodiments, multiple acoustic detection devices 100 may be used to provide noise cancellation during the processing of the acoustic measurements, for example, to enhance the signal-to-noise ratio of the acoustic measurements. For example, multiple acoustic measurements may be compared and processed to cancel noise from an ROV, a choke, or some other subsea equipment component that does not significantly impact the noise / vibrations of the subsea conduit 102.

[0049] This method of collecting and processing acoustic signals enables the construction of a model for the deposit-effected region of the subsea conduit 102. The acoustic properties determined based on the noise / vibration measurements are correlated to deposit characteristics. The acoustic measurement device(s) 100 can be installed temporarily or permanently on or proximate the subsea conduit 102, and methods of installation may enable the acoustic measurement device(s) 100 to be placed circumferentially, placed axially, and / or incorporated into a clamp (e.g., shown in FIG. 4). The acoustic measurement devices 100 do not use radioactive components, and off-shelf hydrophone(s) may be used to construct the acoustic measurement devices 100. This provides a less expensive method for detecting deposits in a subsea conduit 102.

[0050] FIG. 2 is a schematic diagram illustrating the main components of a subsea conduit monitoring and detection system 200 that may identify and detect deposits 202 in a subsea conduit 102. The deposits may be wax, gel, scale, sand, asphaltene, hydrate, or other undesirable material deposits in the subsea conduit 102. The system 200 includes an acoustic measurement device 100 including at least one hydrophone 204 and a frame 206 coupled to the hydrophone 204. The acoustic measurement device 100 is configured for subsea use, and each hydrophone 204 is configured to measure acoustic signals from a subsea location. The frame 206 is configured to position the hydrophone(s) 204 proximate a subsea conduit 102. In some embodiments, the acoustic measurement device 100 may also include an accelerometer 207 coupled to the frame 206, with the frame 206 configured to position the accelerometer 207 against the subsea conduit 102 to detect vibrations of the conduit. In some embodiments, the acoustic measurement device 100 may include a crawling clamp configured to reposition the hydrophone(s) 204 with respect to the subsea conduit 102 via the frame 206. Such a crawling clamp may reposition the hydrophone(s) 204 circumferentially about the subsea conduit 102 and / or longitudinally along a length of the subsea conduit 102.

[0051] The system 200 further includes one or more processors 208 and one or more memories 210 communicatively coupled to the processor(s) 208. These one or more processors 208 and memories 210 may form part of a controller 211 that may be communicatively coupled to the acoustic measurement device 100, as shown. Although only one processor 208 and one memory 210 are shown in the illustrated embodiment, other embodiments may include multiple processors 208 and / or multiple memories 210 distributed across different locations to provide the functionality of the processor 208 and memory 210 described herein.

[0052] The processor 208 is configured to be communicatively coupled to the acoustic measurement device 100. As illustrated, the processor 208 may be located separate from the acoustic measurement device 100 (e.g., in an ROV or at a topside location). However, the processor 208 may be integrated into the acoustic measurement device 100 or distributed between both the acoustic measurement device 100 and another location. Similarly, the memory 210 may be located separate from the acoustic measurement device 100, integrated into the acoustic measurement device 100, or a combination thereof. The memory 210 stores instructions that, when executed by the processor 208, cause the processor 208 to perform one or more tasks.

[0053] The memory-stored instructions may cause the processor 208 to receive, from the acoustic measurement device 100, an output indicative of acoustic signals measured by the hydrophone(s) 204 and / or the accelerometer 207. The acoustic signals may include vibrations, noise, tones, and / or sounds. Each hydrophone 204 may be configured to measure acoustic signals in a frequency range of about 2 Hz to about 200 kHz, or more particularly from about 10 kHz to about 50 kHz.

[0054] The memory-stored instructions may cause the processor 208 to determine at least one acoustic property of the subsea conduit 102 based on the output indicative of acoustic signals measured by the hydrophone(s) 204. The at least one acoustic property may include a sound pressure level (SPL) at a single frequency, multiple frequencies, and / or a range of frequencies measured by the hydrophone 204. The at least one acoustic property may include a flow sound level due to fluid flowing through the subsea conduit 102. The at least one acoustic property may include a flow sound frequency due to fluid flowing through the subsea conduit 102. The at least one acoustic property may include a natural frequency of the subsea conduit 102 between two locations.

[0055] The memory-stored instructions may cause the processor 208 to identify a deposit 202 present inside the subsea conduit 102 based on the acoustic properties. The deposit 202 may be identified based on changes in the at least one acoustic property over time, as discussed in detailabove. The deposit 202 may be identified based on the at least one acoustic property and a monitored flow rate of fluid moving through the subsea conduit 102.

[0056] The memory-stored instructions may cause the processor 208 to estimate one or more physical properties of the deposit 202 within the subsea conduit 102 based on the acoustic properties. The one or more physical properties may include an axial position of the deposit 202 in the subsea conduit 102, a circumferential position of the deposit 202 in the subsea conduit, a shape of the deposit 202, a thickness of the deposit 202, a mass of the deposit 202, a density of the deposit 202, or a combination thereof.

[0057] The subsea conduit monitoring and detection system 200 also includes a power supply 212. As shown in FIG. 2, the power supply 212 may be an on-board power supply, such as a rechargeable battery, located in the acoustic measurement device 100. The power supply 212 may be recharged at a subsea location via an ROV (e.g., 108 of FIG. 1) and / or recharged at a topside location after retrieval of the acoustic measurement device 100 to the surface.

[0058] FIG. 3 illustrates another embodiment of the subsea conduit monitoring and detection system 200, in which the power supply 212 is remote from the acoustic measurement device 100. In FIG. 3, the acoustic measurement device 100 may be a data collection unit configured to be deployed subsea (proximate the subsea conduit 102) and coupled to a subsea power line 300. The subsea power line 300 provides operational power to the acoustic measurement device 100 from a power source 212 at a topside location. The subsea power line 300 may enable the acoustic measurement device 100 to take measurements continuously over a long period of time. In some embodiments, the subsea power line 300 may be packaged with a communication line used to communicate signals of the acoustic measurements from the acoustic measurement device 100 to a topside location for further processing.

[0059] Multiple example embodiments of the acoustic measurement device 100 will now be described with reference to FIGS. 4A-5. FIGS. 4A and 4B illustrate an example acoustic measurement device 100. The acoustic measurement device 100 includes a single hydrophone 204 in a frame 206. In other embodiments, the acoustic measurement device 100 may include multiple hydrophones 204 supported by the frame 206. As illustrated, the frame 206 may include a sound isolation ring 400. The sound isolation ring 400 is configured to be removably placed on the subsea conduit 102 by an ROV (e.g., 108 of FIG. 1) interfacing with an ROV attachment structure 402 on the frame 206. In some embodiments, the sound isolation ring 400 may be constructed from a tire that is cut to fit over the subsea conduit 102. However, other constructions of the sound isolation ring 400 may be used in other embodiments. The sound isolation ring 400 may help isolate thesound of the subsea conduit 102 by providing a barrier to prevent undesired noise (coming from outside of the subsea conduit 102) from reaching the hydrophone(s) 204.

[0060] As illustrated, the acoustic measurement device 100 may include balancing weights 404 coupled to opposite sides of the sound isolation ring 400. These balancing weights 404 may compensate for the buoyancy of the sound isolation ring 400 and ensure upright stability of the acoustic measurement device 100 on the subsea conduit 102. As shown, the balancing weights 404 may be placed internally within the sound isolation ring 400 at both cut ends, thereby keeping the weights 404 from contacting the surface of the subsea conduit 102. The hydrophone 204 may be fixed internally at the top point (furthest point from the cut ends) of the sound isolation ring 400. In other embodiments, the one or more hydrophones 204 may be positioned at different locations along the sound isolation ring. It may be desirable to balance the weight of the hydrophones 204 distributed within the sound isolation ring 400 to maintain the sound isolation ring 400 in position over the subsea conduit 102. The ROV attachment structure 402 may include an ROV handle 406 (e.g., made from rope, cable, steel, or some other material) fixed externally to the top (furthest point from the cut ends) of the sound isolation ring 400. In some embodiments, the ROV attachment structure 402 may also include a monkey-fist type rope or cable 408 fixed externally to the top of the sound isolation ring 400. This monkey-fist type rope or cable 408 may be used for mudline retrieval of the acoustic measurement device 100 in case the device is dropped. FIGS. 4 A and 4B illustrate a relatively rudimentary design for the acoustic measurement device 100, in which every component except the hydrophone(s) 204 may be easily manufactured locally in any country. This may greatly improve the cost and deployment time needed to identify and detect deposits in a subsea conduit 102.

[0061] Operations to perform acoustic measurements using the device 100 of FIGS. 4A and 4B may include the following. The hydrophone 204 is fully charged and time synchronized with a reference system (e.g., global position system (GPS), distributed control system (DCS), ROV, etc.) before deployment. The ROV (e.g., 108 of FIG. 1) places the acoustic measurement device 100 on the subsea conduit 102 using, for example, the handle 406 before driving away. The acoustic measurement device 100 then records acoustic measurements using the hydrophone 204. Production properties of the subsea conduit 102 (e.g., flow rate through the conduit) may also be recorded at the same time to be used in the analysis. The production rate of fluid flowing through the subsea conduit 102 may be adjusted if needed. Later, the ROV retrieves the acoustic measurement device 100 for another data collection (e.g., at another position on the subsea conduit 102) or retrieval to the surface.

[0062] FIG. 5 is a side partial cross-sectional view of another embodiment of an acoustic measurement device 100 attached to a subsea conduit 102 in a portable installation. The acoustic measurement device 100 of FIG. 5 includes an array of multiple hydrophones 204 coupled to and arranged circumferentially about the frame 206. The frame 206 may include a sound isolation ring 400 (similar to FIGS. 4A and 4B) or a semi-flexible clamp connection. Seamlessly integrating multiple hydrophones 204 within the frame 206, this adaptable system can efficiently cover designated circumferential sections of the subsea conduit 102. The placement of the frame 206 with multiple acoustic measurement devices 100 enables acoustic measurements to be taken from each hydrophone 204, thus enabling a processor to track one or more acoustic properties of the subsea conduit 102 over time around the circumference of the subsea conduit 102. In some embodiments, beamforming techniques may be used in the processing of measurements collected via the array of hydrophones 204 to enable more focused determination of acoustic properties of the subsea conduit 102. The attachment of the frame 206 may be effortlessly facilitated by magnets situated on the underside of the hydrophones 204 and / or the frame 206, complemented by the convenience of manipulating integrated ROV handles 500.

[0063] The present disclosure includes multiple examples of methods and acoustic measurement devices (e.g., 100 of FIGS. 1-5) to collect information for identifying and quantifying wax or other deposits in a subsea conduit. The device may be used on any type of subsea conduit that is supported at two points, such as jumpers or trench crossing pipes. FIG. 6 illustrates a jumper 600 on which the disclosed acoustic measurement device may be used. FIG. 6 shows specific locations indicated by arrows 602 along the length of the jumper 600 where the acoustic measurement device may be positioned. With the acoustic measurement device positioned along a subsea conduit (e.g., jumper 600) between two support points, the acoustic measurement device may collect measurements that can be used to determine a natural frequency of the subsea conduit. The disclosed systems and methods may be used on other types of subsea conduits as well, such as a pipelines resting on the seafloor.

[0064] FIG. 7 is a process flow diagram illustrating a method 700 for monitoring and detecting a deposition inside a subsea conduit. The usage of the method 700 is independent of duration of installation (i.e., whether permanent or temporary) and independent of installation period (e.g., new conduit, used conduit). The method 700 enables both monitoring (i.e., observing the progression of deposition) and detection (i.e., determining the location of a deposit). It should be noted that the illustrated method 700 is exemplary, and certain steps of the method 700 may be added, removed, or reordered from what is shown in FIG. 7. Blocks illustrated in dashed lines, for example, may represent optional steps.

[0065] At block 702, the method 700 includes positioning at least one hydrophone of an acoustic measurement device proximate a subsea conduit via a frame of the acoustic measurement device. In one example, the at least one hydrophone may be positioned proximate the subsea conduit prior to the subsea conduit being positioned subsea. In another example, the at least one hydrophone may be positioned proximate the subsea conduit after the subsea conduit is positioned subsea. The acoustic measurement device may be deployed to a subsea location via an ROV. The acoustic measurement device may later be moved or selectively retrieved from the subsea location via the same or a different ROV.

[0066] At block 704, the method 700 includes measuring acoustic signals from a subsea location using the at least one hydrophone. The acoustic signals may include detected vibrations, noise, tones, or sounds. This may include intermittently measuring the acoustic signals, or continuously measuring the acoustic signals. At block 706, the method 700 includes receiving, at a processor, an output indicative of acoustic signals measured by the hydrophone.

[0067] At block 708, the method 700 includes determining, by the processor, at least one acoustic property of the subsea conduit based on the output indicative of acoustic signals measured by the hydrophone(s). The processor may analyze the output indicative of acoustic signals in both time and frequency domains to determine the at least one acoustic property. The at least one acoustic property may include a sound pressure level (SPL) of a single frequency, multiple frequencies, and / or a range of frequencies measured by the hydrophone(s).

[0068] At block 710, the method 700 includes identifying, by the processor, a deposit present inside the subsea conduit based on the at least one acoustic property. In some embodiments, identifying the deposit may involve the following: monitoring an SPL determined based on the output indicative of acoustic signals measured by the hydrophone, determining an expected SPL from analysis of historical data, simulations, or analogs, and calculating a damping of the monitored SPL from the expected SPL. As discussed further below, the level of damping may be correlated to deposit characteristics.

[0069] At block 712, the method 700 may include monitoring a flow rate of fluid through the subsea conduit. In such embodiments, the deposit may be identified (block 710) based on the at least one acoustic property and the monitored flow rate. At block 714, the method 700 may include establishing a baseline pattern of the one or more acoustic properties relative to the flow rate. In such embodiments, the deposit may be identified (block 710) based on the at least one acoustic property, the monitored flow rate, and the baseline pattern.

[0070] At block 716, the method 700 includes estimating, via the processor, one or more physical properties of the deposit within the subsea conduit based on the at least one acousticproperty. Damping of SPL from an expected value at a single position can be translated to a relative thickness of the deposit at that position. As such, estimating the physical properties of the deposit may include determining a relative thickness of the deposit based on the calculated SPL damping. At block 718, the method 700 may include generating an acoustic image based on the calculated SPL damping at one or more frequencies. The processor may calculate SPL damping at multiple selected frequencies, which may improve the resolution of the acoustic imaging method.

[0071] At block 720, the method 700 may include moving the at least one hydrophone with respect to the subsea conduit before measuring additional acoustic signals via the at least one hydrophone. The hydrophone(s) may be moved in an axial direction with respect to the subsea conduit. Additionally, or alternatively, the hydrophone(s) may be moved in a circumferential direction with respect to the subsea conduit. Steps 704, 706, 708, 710, and 716 may then be repeated to collect additional measurements to estimate properties of the deposit at different locations. At block 722, the method 700 may include generating a map of the deposit in an axial direction and a circumferential direction along the subsea conduit based on the estimated physical properties of the deposit collected at the different locations.

[0072] At block 724, the method 700 may include designing a treatment for the subsea conduit based on the estimated one or more physical properties of the deposit. The estimated physical properties of the deposit may include type or density of the deposit as well as thickness of the deposit at different locations within the subsea conduit. This information is useful in designing a proper treatment (e.g., chemical treatment program, or mechanical removal procedure) to remove the deposit. The method 700 may include performing a treatment (e.g., the designed treatment) on the subsea conduit and repeating at least steps 704, 706, 708, 710, and 716 while performing the treatment to monitor the physical properties of the deposit within the subsea conduit in response to the treatment. In this way, the acoustic measurement device may be used to confirm the efficacy of the treatment.

[0073] A device and method in accordance with the present disclosure were tested according to the following Example 1.

[0074] Before the testing was performed, initial modeling was done to determine an expected acoustic response for a pipe with alginate (a wax analog) and a pipe without alginate. The modeling used Fast Fourier Transformation to calculate sound amplitudes at given frequencies, as shown in FIG. 16. The plot in FIG. 16 shows that amplitude of certain frequencies in the flow sound is dampened (attenuated) by the deposited material (alginate) inside of the pipe. FIG. 17 is a polar plot illustrating the average frequency response from this acoustic modeling. The plot of FIG. 17 shows the effect of alginate in the pipe relative to baseline acoustic levels, averaging the acousticresponse in dB at frequencies of 10 kHz, 20 kHz, 30 kHz, 40 kHz, and 50 kHz. Based on this acoustic modeling, the inventors believe that monitoring the sound around a pipe and analyzing the amplitude of the flow sound within a specific frequency range using FFT (Fast Fourier Transformation) could be used to map the thickness profile of the deposited material (wax / alginate) inside the pipe. This was then tested in Example 1.Example 1

[0075] This example evaluated in laboratory conditions whether wax buildup in undersea natural gas conduits might be detectable using passive acoustics. The wax buildup tends to be non- axisymmetric, with there being thicker and thinner regions of the deposit. The objective in this example was to determine if this variation in wax thickness may result in varying levels of sound amplitude around the circumference of the conduit, which may be detectable via a hydrophone.

[0076] The steps performed in the testing included: taking baseline measurements of the soundfield in an empty pipe segment; casting alginate in the pipe segment; and taking measurements of the soundfield in the pipe segment with cast alginate. FIGS. 8A and 8B schematically illustrate the test setup for the baseline measurements (FIG. 8A) and for the measurements with cast alginate (FIG. 8B). For the test setup, a hydrophone 204 was mounted on a frame 206 to take sound measurements around a pipe segment 800 during testing. The frame 206 included an arm 802 to which the hydrophone 204 was attached and a bearing 804 to rotate the hydrophone 204 around the exterior of the pipe segment 800. As shown, a plate 806 was rotatably coupled to the top of the pipe segment 800 via the bearing 804, and the arm 802 extended downward from the plate 806.

[0077] For the initial test setup (FIG. 8A), a steel pipe segment 800 was used with a length of 4 feet, an inner diameter of 7.98 inches, and an outer diameter of 8.625 inches. The pipe segment 800 was sealed on one end and placed vertically in a tank of water 808. The plate 806 was mounted to the top of the pipe segment 800 via a 12.75-inch diameter bearing 804. The large bearing diameter was chosen to ensure stable positioning of the hydrophone 204 in the water 808. Marks were added to the bearing 804 at every 15 degrees to use for positioning the hydrophone 204. The hydrophone 204 was mounted via the arm 802 and rotating plate 806 that positioned the hydrophone 204 in the water 808 approximately 40 mm from the exterior wall of the pipe segment 800. This 40 mm distance was chosen to represent an estimate of the closest distance hydrophones could be positioned to a subsea conduit in the field. A sound source 810 was positioned centrally inside the pipe segment 800 at the same depth as the hydrophone 204 outside of the pipe segment 800. The sound source 810 was controlled to play frequency sweeps from 10 kHz to 200 kHz insteps of 10 kHz. The tones were short so as to avoid effects of reflections from the water tank walls in the measurements and only measure the sound passing through the pipe segment 800.

[0078] For the second test setup (FIG. 8B), the same general test setup is used, but with alginate 812 added. The alginate 812 was used as a stand-in for hydrocarbon wax / gel deposits. The alginate 812 was cast between the pipe segment 800 and an inner pipe segment (not shown) with a diameter of 7 inches. The inner pipe segment was offset to the side of the steel pipe segment 800 to produce a volume of alginate 812 that varied around the pipe segment 800 from a minimum thickness of 2- 3 mm to a maximum thickness of 20 mm. FIG. 9 shows a partial cross section of the second test setup from above. The sound source 810 is shown in the center of the pipe segment 800, along with the alginate material 812 on the inner surface of the pipe segment 800. The hydrophone 204 is located proximate the exterior of the pipe segment 800.

[0079] The testing involved first verifying functionality of sound proj ection and recording with the sound source 810 and the hydrophone 204 positioned inside and outside the pipe segment 800, respectively. This verification was provided with the initial test setup of FIG. 8 A. FIG. 10 shows a spectrogram of a recording (x-axis is time, y-axis is frequency, and color indicates sound intensity) taken by the hydrophone 204 during the verification. As illustrated, adequate signal levels were recorded up to approximately 120 kHz. Above this frequency, tones were lost in the background noise.

[0080] In addition, sound recordings were taken to measure the sound flight time between a ping start and ping arrival at the hydrophone 204. This sound flight time value can be used later in data processing. FIG. 11 shows a recording of a single 40 kHz tone. For this tone, the sound source produced the sound at 1.824 seconds (1100 on FIG. 11), and the flight time of sound was approximately 330 ps, which agreed with the theoretical value of 324 ps shown in Table 1 below. The period that is used to calculate SPL values is shown in FIG. 11 between times 1102 and 1104. This keeps reflections from the tank environment out of the evaluated portion of the signal.Table 1

[0081] After the initial verification and time-of-flight measurement, baseline acoustic measurements were taken using the test setup of FIG. 8 A (without alginate). The sound source 810 emitted frequency sweeps, and sound recordings were taken via the hydrophone 204. The testing involved taking a complete set of measurements around the circumference of the pipe segment 800 at 30-degree steps in angle. This provided a baseline to compare against the measurements of the second test setup. FIG. 12 gives the frequency responses at each angular location around the pipe segment without alginate. FIG. 12 is a plot of SPL (in dB re 1 pPa) with respect to frequency, with the different colored lines representing the different angular positions from which the measurements were taken. The noise floor for the hydrophone is approximately 28 dB re 1 pPa, which agrees with the previous statement that 120 kHz was the upper end of the measurable frequency band for the pipe segment on its own. As illustrated, there is a slight amount of variability between points around the circumference of the pipe segment.

[0082] Next, the alginate was cast inside the pipe segment to form the test setup of FIG. 8B. In this example, the thinnest section of alginate was located between 275 and 15 degrees (roughly positioned around 0). The testing then involved taking a complete set of measurements around the circumference of the pipe segment 800 with the alginate 812 at 30-degree steps in angle. These measurements were done twice, and there was some variability between the two measurements that may have been due to degradation of the alginate 812 since the measurements were taken on separate days. FIGS. 13 A and 13B are the frequency response plots for the two measurements run with the test setup with alginate. FIGS. 13 A and 13B are plots of SPL (in dB re 1 pPa) with respect to frequency, with the different colored lines representing the different angular positions from which the measurements were taken. When compared to the measurements without alginate (FIG. 12), there is a large amount of variability in amplitude between the different points at lower frequencies. This is indicative of there being differences between the regions of low and high alginate thickness. There is also a fair amount of SPL damping occurring, with the maximum amplitudes being lower once the alginate was added.

[0083] The comparisons between the measurements with and without alginate appear to confirm that the alginate dampens the sound and that there is a good correlation between the thickness of the alginate and the amount of SPL damping. FIG. 14 illustrates a comparison of the angular SPL response at a series of frequencies. FIG. 14 is a plot of SPL (in dB re 1 pPa) with respect to angular position around the circumference of the pipe segment for measurements taken at certain frequency levels in both test setups (with and without alginate). As shown, the SPL without the alginate is relatively constant about the circumference of the pipe segment at each frequency level, whereas the SPL with the alginate has a significant amount of variation about thecircumference of the pipe segment at the different frequency levels. This change in SPL with the alginate closely aligns with the approximate angles of maximum and minimum alginate thickness, which are also denoted on the plot.

[0084] The two sets of sound field measurements with the alginate produced somewhat differing results in terms of the frequencies where the variation due to the alginate was noticeable. FIGS. 15A-15H are a series of polar plots comparing the baseline measurements with the first and second alginate measurements for frequencies from 10 kHz-80 kHz. The first test (“alginate 1” on the plots) only showed measurable variation up to 50 or 60 kHz, whereas the second test (“alginate2”) showed a relatively clear difference up to about 80 kHz. Each plot also shows the approximate location of the point of minimum alginate thickness.

[0085] As visible from FIGS. 14-15H, there was a clear difference in the sound pressure levels between the regions of thicker and thinner alginate within the test setup. This supports a correlation between the location of the thicker regions of the alginate deposit and the amount of SPL damping. Since the alginate material has similar damping properties to hydrocarbon wax deposits, the test results indicate that an acoustic measurement device using one or more hydrophones may be used to detect wax distribution within a subsea conduit. Thus, the disclosure provides a system and method for monitoring and characterizing deposition within subsea conduits in a manner that can be performed regularly and with lower cost than previous methods (e.g., CT imaging).

[0086] Additional acoustic modeling was also performed to predict external noise levels from pipe with alginate material inside. The acoustic modeling included the following process: calculating the internal flow noise in a jumper, without and with wax (0.075” thick uniform deposition assume along the length of the jumper; calculating the pipe wall transmission loss (upper and lower bounds); calculating the external noise level measured at a location 1 meter from the pipe wall; and comparing the results with Wenz criteria. The results of this acoustic modeling supported that an increase in flow velocity through the pipe due to the presence of the alginate would increase the noise levels to be measured from outside the pipe. In particular, the external noise levels were predicted to increase by approximately 6-7 dB due to a uniform wax deposition along the jumper of 0.705” thickness under identical flow conditions. The external noise signature was predicted to peak between 1 kHz and 4 kHz. The results indicated that the predicted external noise levels fall within the upper and lower limits of the prevailing background noise. The lower bound noise levels (calculated using the lower bound transmission loss curve) may be more challenging to detect depending on the background levels, so the upper bound external noise levels may indicate a better possibility of detection. The results of acoustic modeling also showed that relatively small variations in the hydrophone distance from the pipe wall would result in a variationin external noise level of the same order of magnitude as the difference that a change in flow velocity would give. Therefore, using a consistent location from the pipe wall for performing acoustic detection may be important. It may be advantageous to locate the hydrophone as close as practicable to the wall in terms of signal detection.

[0087] The disclosure includes the following illustrative embodiments.

[0088] Embodiment 1 : A subsea conduit monitoring and detection system, including: an acoustic measurement device configured for subsea use, the acoustic measurement device including: at least one hydrophone configured to measure acoustic signals from a subsea location; and a frame coupled to the hydrophone, wherein the frame is configured to position the hydrophone proximate a subsea conduit; a processor configured to be communicatively coupled to the acoustic measurement device; and a memory communicatively coupled to the processor, the memory storing instructions that, when executed by the processor, cause the processor to: receive, from the acoustic measurement device, an output indicative of acoustic signals measured by the hydrophone; determine at least one acoustic property of the subsea conduit based on the output; identify a deposit present inside the subsea conduit based on the at least one acoustic property; and estimate one or more physical properties of the deposit within the subsea conduit based on the at least one acoustic property.

[0089] Embodiment 2: The system of Embodiment 1, wherein the instructions, when executed by the processor, cause the processor to identify the deposit present inside the subsea conduit based on changes in the at least one acoustic property over time.

[0090] Embodiment 3 : The system of Embodiment 1 , wherein the at least one acoustic property includes a flow sound level due to fluid flowing through the subsea conduit.

[0091] Embodiment 4: The system of Embodiment 1, wherein the at least one acoustic property includes a flow sound frequency due to fluid flowing through the subsea conduit.

[0092] Embodiment 5 : The system of Embodiment 1 , wherein the at least one acoustic property includes a natural frequency of the subsea conduit.

[0093] Embodiment 6: The system of Embodiment 1, wherein the acoustic measurement device further includes an accelerometer coupled to the frame, wherein the frame is configured to position the accelerometer against the subsea conduit.

[0094] Embodiment 7: The system of Embodiment 1, wherein the one or more physical properties of the deposit includes an axial position of the deposit in the subsea conduit, a circumferential position of the deposit in the subsea conduit, a shape of the deposit, a thickness of the deposit, a mass of the deposit, a density of the deposit, or a combination thereof.

[0095] Embodiment 8: The system of Embodiment 1, wherein the frame includes a sound isolation ring with a remote operated vehicle (ROV) interface, wherein the sound isolation ring is configured to be removably placed on the subsea conduit by an ROV.

[0096] Embodiment 9: The system of Embodiment 1, wherein the acoustic measurement device includes an array of multiple hydrophones coupled to and arranged circumferentially about the frame.

[0097] Embodiment 10: The system of Embodiment 1, wherein the acoustic measurement device includes a crawling clamp configured to reposition the at least one hydrophone with respect to the subsea conduit via the frame.

[0098] Embodiment 11 : The system of Embodiment 1, wherein the acoustic measurement device is a data collection unit configured to be deployed subsea, the data collection unit being coupled to a subsea power line.

[0099] Embodiment 12: The system of Embodiment 1, wherein the acoustic signals include vibrations, noise, tones, and / or sounds.

[0100] Embodiment 13: The system of Embodiment 1, wherein the acoustic measurement device is configured to be permanently installed on or proximate the subsea conduit.

[0101] Embodiment 14: The system of Embodiment 1, wherein the acoustic measurement device is configured to be temporarily installed on or proximate the subsea conduit.

[0102] Embodiment 15: The system of Embodiment 1, wherein the hydrophone is configured to measure acoustic signals in a frequency range of about 2 Hz to about 200 kHz.

[0103] Embodiment 16: The system of Embodiment 15, wherein the hydrophone is configured to measure acoustic signals in a frequency range of about 10 kHz to about 50 kHz.

[0104] Embodiment 17: The system of Embodiment 1, further including the subsea conduit, wherein the subsea conduit is a subsea jumper or a trench crossing conduit and is supported at two points.

[0105] Embodiment 18: A subsea conduit monitoring and detection method, including: positioning at least one hydrophone of an acoustic measurement device proximate a subsea conduit via a frame of the acoustic measurement device; measuring acoustic signals from a subsea location using the at least one hydrophone; receiving an output indicative of acoustic signals measured by the hydrophone; determining at least one acoustic property of the subsea conduit based on the output; identifying a deposit present inside the subsea conduit based on the at least one acoustic property; and estimating one or more physical properties of the deposit within the subsea conduit based on the at least one acoustic property.

[0106] Embodiment 19: The method of Embodiment 18, wherein the at least one acoustic property includes a sound pressure level (SPL) of a single frequency, multiple frequencies, and / or a range of frequencies measured by the hydrophone.

[0107] Embodiment 20: The method of Embodiment 19, wherein identifying the deposit includes: monitoring the SPL determined based on the output; determining an expected SPL from analysis of historical data, simulations, or analogs; and calculating damping in the monitored SPL from the expected SPL.

[0108] Embodiment 21 : The method of Embodiment 20, wherein estimating the one or more physical properties of the deposit includes determining a relative thickness of the deposit based on the calculated damping.

[0109] Embodiment 22: The method of Embodiment 19, wherein identifying the deposit includes: monitoring the SPL determined based on the output; determining an expected SPL from analysis of historical data, simulations, or analogs; and calculating damping in the monitored SPL from the expected SPL.

[0110] Embodiment 23: The method of Embodiment 22, further including calculating SPL damping at multiple selected frequencies.

[0111] Embodiment 24: The method of Embodiment 22, further including generating an acoustic image based on the calculated damping.

[0112] Embodiment 23: The method of Embodiment 18, further including: monitoring a flow rate of fluid through the subsea conduit; and identifying the deposit present inside the subsea conduit based on the at least one acoustic property and the monitored flow rate.

[0113] Embodiment 24: The method of Embodiment 23, further including: establishing a baseline pattern of one or more acoustic properties relative to flow rate; and identifying the deposit based on the at least one acoustic property, the monitored flow rate, and the baseline pattern.

[0114] Embodiment 25: The method of Embodiment 18, further including generating a map of the deposit in an axial direction and a circumferential direction along the subsea conduit.

[0115] Embodiment 26: The method of Embodiment 18, further including designing a treatment for the subsea conduit based on the estimated one or more physical properties of the deposit.

[0116] Embodiment 27: The method of Embodiment 18, further including: performing a treatment on the subsea conduit; measuring the acoustic signals from the subsea location while performing the treatment; and monitoring the one or more physical properties of the deposit within the subsea conduit while performing the treatment.

[0117] Embodiment 28: The method of Embodiment 18, further including: moving the at least one hydrophone with respect to the subsea conduit; and after moving the at least one hydrophone, measuring additional acoustic signals via the at least one hydrophone.

[0118] Embodiment 29: The method of Embodiment 28, wherein the at least one hydrophone is moved in an axial direction with respect to the subsea conduit.

[0119] Embodiment 30: The method of Embodiment 28, wherein the at least one hydrophone is moved in a circumferential direction with respect to the subsea conduit.

[0120] Embodiment 31 : The method of Embodiment 18, further including deploying the acoustic measurement device to a subsea location via a remote operated vehicle (ROV).

[0121] Embodiment 32: The method of Embodiment 18, further including selectively retrieving the acoustic measurement device from the subsea location via the same or a different ROV.

[0122] Embodiment 33: The method of Embodiment 18, wherein the at least one hydrophone is positioned proximate the subsea conduit prior to the subsea conduit being positioned subsea.

[0123] Embodiment 34: The method of Embodiment 18, wherein the at least one hydrophone is positioned proximate the subsea conduit after the subsea conduit is positioned subsea.

[0124] Embodiment 35: The method of Embodiment 18, further including intermittently measuring the acoustic signals from the subsea location using the at least one hydrophone.

[0125] Embodiment 36: The method of Embodiment 18, further including continuously measuring the acoustic signals from the subsea location using the at least one hydrophone.

[0126] Embodiment 37: The method of Embodiment 18, further including analyzing the output indicative of acoustic signals in both time and frequency domains to determine the at least one acoustic property.

[0127] Embodiment 38: The method of Embodiment 18, wherein the deposit includes a wax, gel, inorganic scale, sand, asphaltene, and / or hydrate.

[0128] Embodiment 39: The method of Embodiment 18, further including: providing an active source of sound or vibration at the subsea conduit; and measuring the acoustic signals resulting from the active source of sound or vibration via the at least one hydrophone.

[0129] Embodiment 40: The method of Embodiment 18, wherein the acoustic signals measured via the at least one hydrophone result from a passive source of noise or vibration.

[0130] Embodiments illustrated under any heading or in any portion of the disclosure may be combined with embodiments illustrated under the same or any other heading or other portion of the disclosure unless otherwise indicated herein or otherwise clearly contradicted by context. For example, and without limitation, embodiments described in dependent claim format for a givenembodiment (e.g., the given embodiment described in independent claim format) may be combined with other embodiments (described in independent claim format or dependent claim format).

[0131] Although embodiments described herein are made with reference to example embodiments, it should be appreciated by those skilled in the art that various modifications are well within the scope and spirit of this disclosure. Those skilled in the art will appreciate that the example embodiments described herein are not limited to any specifically discussed application and that the embodiments described herein are illustrative and not restrictive. From the description of the example embodiments, equivalents of the elements shown therein will suggest themselves to those skilled in the art, and ways of constructing other embodiments using the present disclosure will suggest themselves to practitioners of the art. Therefore, the scope of the example embodiments is not limited herein.

Claims

CLAIMS1. A subsea conduit monitoring and detection system, comprising: an acoustic measurement device configured for subsea use, the acoustic measurement device comprising: at least one hydrophone configured to measure acoustic signals from a subsea location; and a frame coupled to the hydrophone, wherein the frame is configured to position the hydrophone proximate a subsea conduit; a processor configured to be communicatively coupled to the acoustic measurement device; and a memory communicatively coupled to the processor, the memory storing instructions that, when executed by the processor, cause the processor to: receive, from the acoustic measurement device, an output indicative of acoustic signals measured by the hydrophone; determine at least one acoustic property of the subsea conduit based on the output; identify a deposit present inside the subsea conduit based on the at least one acoustic property; and estimate one or more physical properties of the deposit within the subsea conduit based on the at least one acoustic property.

2. The system of claim 1, wherein the instructions, when executed by the processor, cause the processor to identify the deposit present inside the subsea conduit based on changes in the at least one acoustic property over time.

3. The system of claim 1, wherein the at least one acoustic property comprises a flow sound pressure level due to fluid flowing through the subsea conduit.

4. The system of claim 1, wherein the at least one acoustic property comprises a flow sound frequency due to fluid flowing through the subsea conduit.

5. The system of claim 1, wherein the at least one acoustic property comprises a natural frequency of the subsea conduit.

6. The system of claim 1, wherein the acoustic measurement device further comprises an accelerometer coupled to the frame, wherein the frame is configured to position the accelerometer against the subsea conduit.

7. The system of claim 1, wherein the one or more physical properties of the deposit comprises an axial position of the deposit in the subsea conduit, a circumferential position of the deposit in the subsea conduit, a shape of the deposit, a thickness of the deposit, a mass of the deposit, a density of the deposit, or a combination thereof.

8. The system of claim 1, wherein the frame comprises a sound isolation ring with a remote operated vehicle (ROV) interface, wherein the sound isolation ring is configured to be removably placed on the subsea conduit by an ROV.

9. The system of claim 1, wherein the acoustic measurement device comprises an array of multiple hydrophones coupled to and arranged circumferentially about the frame.

10. The system of claim 1, wherein the acoustic measurement device comprises a crawling clamp configured to reposition the at least one hydrophone with respect to the subsea conduit via the frame.

11. The system of claim 1, wherein the acoustic measurement device is a data collection unit configured to be deployed subsea, the data collection unit being coupled to a subsea power line.

12. A subsea conduit monitoring and detection method, comprising: positioning at least one hydrophone of an acoustic measurement device proximate a subsea conduit via a frame of the acoustic measurement device; measuring acoustic signals from a subsea location using the at least one hydrophone; receiving an output indicative of acoustic signals measured by the hydrophone; determining at least one acoustic property of the subsea conduit based on the output; identifying a deposit present inside the subsea conduit based on the at least one acoustic property; andestimating one or more physical properties of the deposit within the subsea conduit based on the at least one acoustic property.

13. The method of claim 12, wherein the at least one acoustic property comprises a sound pressure level (SPL) of a single frequency, multiple frequencies, and / or a range of frequencies measured by the hydrophone.

14. The method of claim 13, wherein identifying the deposit comprises: monitoring the SPL determined based on the output; determining an expected SPL from analysis of historical data, simulations, or analogs; and calculating damping in the monitored SPL from the expected SPL.

15. The method of claim 14, wherein estimating the one or more physical properties of the deposit comprises determining a relative thickness of the deposit based on the calculated damping.

16. The method of claim 12, further comprising: monitoring a flow rate of fluid through the subsea conduit; and identifying the deposit present inside the subsea conduit based on the at least one acoustic property and the monitored flow rate.

17. The method of claim 12, further comprising generating a map of the deposit in an axial direction and a circumferential direction along the subsea conduit.

18. The method of claim 12, further comprising designing a treatment for the subsea conduit based on the estimated one or more physical properties of the deposit.

19. The method of claim 12, further comprising: performing a treatment on the subsea conduit; measuring the acoustic signals from the subsea location while performing the treatment; and monitoring the one or more physical properties of the deposit within the subsea conduit while performing the treatment.

20. The method of claim 12, further comprising: moving the at least one hydrophone with respect to the subsea conduit; and after moving the at least one hydrophone, measuring additional acoustic signals via the at least one hydrophone.

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