Automated Interpretation of Deposition Volumes

The present technology pertains to a well system for extracting materials, and more particularly, to automating the interpretation of diameter changes in the flowline for well or flowline facilities.

A well or flowline system comprises a well-drilling or pipe laying system to form the well or flowline and a pumping system to move materials in the well or flowline. These systems include equipment and machinery designed to extract and transport natural resources, such as water, oil, or gas, from the ground. The system typically includes a drilling rig, which is used to bore a hole into the earth's crust, and a casing, which is a steel pipe that lines the well and prevents the walls from collapsing. The drilling process begins with the placement of a drill bit at the end of a drill string. The drill bit is then rotated, using a motor or a manual mechanism, to create a hole in the ground. As the hole is drilled, the drill string is gradually lengthened by adding more sections of pipe. The process continues until the desired depth is reached. When this fluid is produced, it is transported along a flowline for processing and distribution at gathering stations and refineries.

Once the drilling is complete, a casing is installed into the well to protect it from collapse and prevent contamination of the extracted resources. The casing is typically cemented into place to seal off any potential pathways for groundwater to enter the well. Once the well is prepared, a well-pumping system is installed to extract the resources from the well. The type of pump used depends on the type of resource being extracted, as well as the depth and diameter of the well. For example, a submersible pump may be used for a water well, while a reciprocating pump may be used for an oil well.

Certain aspects of this disclosure are provided below. Some of these aspects may be applied independently and some of them may be applied in combination as would be apparent to those of skill in the art. In the following description, for the purposes of explanation, specific details are set forth in order to provide a thorough understanding of aspects of the application. However, it will be apparent that various aspects may be practiced without these specific details. The figures and descriptions are not intended to be restrictive.

The ensuing description provides example aspects only and is not intended to limit the scope, applicability, or configuration of the disclosure. Rather, the ensuing description of the example aspects will provide those skilled in the art with an enabling description for implementing an example aspect. It should be understood that various changes may be made in the function and arrangement of elements without departing from the spirit and scope of the application as set forth in the appended claims.

The terms “exemplary” and/or “example” are used herein to mean “serving as an example, instance, or illustration.” Any aspect described herein as “exemplary” and/or “example” is not necessarily to be construed as preferred or advantageous over other aspects. Likewise, the term “aspects of the disclosure” does not require that all aspects of the disclosure include the discussed feature, advantage or mode of operation.

As previously described, well and flowline systems (or a well site) include a large number of interoperating components, and many of these components experience wear and tear, failure, adverse conditions, and other general issues that may affect operation of the well site. In one illustrative aspect, an electric submersible pump system, which is also referred to as an artificial lift pumping system, can be deployed into the downhole environment (e.g., into the well) and experiences high temperature, immense pressure, fluid-borne abrasives, excessive gas, scale, and variable flow rate environments. In some cases, operators of the well site may implement a records system to document the operation of the various components, adverse conditions, and data related to the adverse conditions. One type of data tracked and recorded is the pressure profiles of pipelines which can be undertaken by various equipment, including non-invasive equipment. The pressure profiles can be used to determine the contours of the inner diameter of a pipeline, providing a profile of potential deposits that take place while operating a well system. During the operation of the well or flowline system, including oil exploration, production, transportation, refining, and chemical processing, surfaces may become contaminated with deposits from crude oils. Some chemical species such as asphaltenes, paraffins, and mineral scales, for example, may be naturally present in crude oils. These chemical species, among others, may deposit on surfaces such as tubulars in the case of oil exploration, or on surfaces of pipelines during oil transport. Identification of these deposits, as well as their rate of change, allows for the operators to avoid failure and blockages of the pipelines while maintaining operations.

Operators are able to clean-out deposits found in a fluidic channel. After the fluidic channel is inspected at certain points and deposits are identified, a portion of the fluidic channel with deposits can be cleaned and/or replaced by any suitable method. For example, the operator can determine a cleaning process to remove the deposit from the fluidic channel based on the properties of the deposit. In some examples, the operator can initiate the cleaning process to remove the deposit from the fluidic channel. In some examples, the operator can initiate the cleaning process automatically without human assistance. In some examples, a user can begin the cleaning process by providing instructions to a controller. As the location and the identification and/or properties of each deposit in the fluidic channel is known, a more precise and targeted approach to address the deposits can be performed. Cleaning can take place via the use of pipeline inspection gauges (PIG) that operate within the fluidic channel to clean out deposits. The present disclosure allows an operator to identify the location of a deposit and the characteristics of the deposit and flowline to better implement cleaning out the deposit.

The use of off-site computing systems to undertake the interrogation of flowlines and identify depositions present can be intensive and time-consuming, which can lead to reduced measurements and time-delayed identification of deposits. Such off-site methods can also be expensive to operate and impractical to deploy in the field. What is needed is a process that is cost-effective, timely, easy to deploy, and avoids the use of memory and processing power only available with access to a full off-site facility. Accordingly, the present disclosure discusses a new method using an updated and improved model to determine deposition levels, the model incorporates regression analysis and neural networks to create a quick and efficient output that calculates depositions in a pipeline using the model in combination with previous measured data.

The disclosed technology addresses the foregoing by using a neural network and multivariate regression analysis to quickly and efficiently update the calculation of depositions in a pipe using the known state of the pipe from previous measurements, the current measurements, and the regression model. In various embodiments, a system may include one or more processors and at least one computer-readable storage medium storing instructions which, when executed by the one or more processors, cause the one or more processors to receive flowline data from a pressure sensor, determine, via analysis of the flowline data, the presence of a deposition, and build a predictive model based on legacy data observations and the presence of the deposition.

This disclosure includes tools and systems that allow for non-intrusive methodologies that, given a deposit's location in a fluidic channel such as a pipeline, wellbore, flowline, or well, can determine the basic properties of the deposit based on its physical attributes without the deployment of intrusive devices. Non-intrusive methodologies can enable better decisions to be made based on an understanding of deposit location using cost-effective equipment that can be deployed and maintained on-site for periodic inspections and reviews. By non-intrusively determining the properties of the deposits, delays that can result in loss of revenue from reduced or halted product flows, cost multiple millions of dollars per pipeline segment, or are well-treated with ineffective chemical or physical treatments can be avoided. Quick identification of deposits without costly deployment of multiple resources can enable a shorter delay in decisions regarding effective treatments and enable superior maintenance of targeted flow rates.

The ability to identify deposits without requiring deployment of equipment or sensors along the pipeline or wellbore length represents a major step forward and will support application of subsequent treatments in a manual or automated methodology.

The system can utilize acoustic or pressure waves induced by one or more pressure devices and measured by one or more sensors to characterize a variety of potential deposit properties which will be required for identification of various deposit types. The properties can include, for example: Porosity, Permeability, Elasticity, Darcy-Weisbach friction factor, Reynolds number, Surface roughness, etc. Analysis of these properties in conjunction with knowledge of the deposit's location and an ideal simulated model can provide identification of deposit material for support of treatment decisions.

Additional details and aspects of the present disclosure are described in more detail below with respect to the figures. The method can be employed using a pressure transducer, e.g., sensor, utilized in an exemplary system shown, for example, in.

is a schematic diagram of an example system for logging while drilling (LWD) operating environment of a well site, in accordance with various aspects of the disclosure.

In some aspects, the systemcan be a drilling arrangement as shown in, that exemplifies an LWD configuration in a wellbore drilling scenario. The LWD typically incorporates sensors that acquire formation data. The drilling arrangement ofalso exemplifies measurement while drilling (MWD) and utilizes sensors to acquire data from which the wellbore's path and position in three-dimensional space may be determined.shows a drilling platformequipped with a derrickthat supports a hoistfor raising and lowering a drill string. The hoistsuspends a top drivesuitable for rotating and lowering the drill stringthrough a well head. A drill bitmay be connected to the lower end of the drill string. As the drill bitrotates, the drill bitcreates a wellborethat passes through at least one subterranean formation. A pumpcirculates drilling fluid through a supply pipeto top drive, down through the interior of the drill string, and out orifices in the drill bitinto the wellbore. The drilling fluid returns to the surface via the annulus around the drill string, and into a retention pit. The drilling fluid transports cuttings from the wellboreinto the retention pitand the drilling fluid's presence in the annulus aids in maintaining the integrity of the wellbore. Various materials may be used for drilling fluid, including oil-based fluids and water-based fluids.

In some aspects, at least one logging toolmay be integrated into the bottom-hole assemblynear the drill bit. As the drill bitextends the wellborethrough the subterranean formation, logging toolcollect measurements relating to various formation properties as well as the orientation of the tool and various other drilling conditions. In some cases, the logging tools interface with various sensors and equipment. The bottom-hole assemblymay also include a telemetry subto transfer measurement data to a surface receiverand to receive commands from the surface. In at least some cases, the telemetry subcommunicates with a surface receiverusing mud pulse telemetry. In some instances, the telemetry subdoes not communicate with the surface, but rather stores logging data for later retrieval at the surface when the logging assembly is recovered.

Each logging toolmay include one or more tool components spaced apart from each other and communicatively coupled by one or more wires and/or another communication arrangement. The logging toolmay also include one or more computing devices communicatively coupled with one or more of the tool components. The one or more computing devices may be configured to control or monitor the performance of the tool, process logging data, and/or carry out one or more aspects of the methods and processes of the present disclosure.

In at least some instances, the at least one logging toolmay communicate with a surface receiverby a wire, such as a wired drill pipe. In other cases, the at least one logging toolmay communicate with a surface receiverby wireless signal transmission, such as ground penetrating radar. In at least some cases, one or more of the logging toolsmay receive electrical power from a wire that extends to the surface, including wires extending through a wired drill pipe.

In some aspects, a collaris a frequent component of a drill stringand generally resembles a very thick-walled cylindrical pipe, typically with threaded ends and a hollow core for the conveyance of drilling fluid. In some cases, more than one collarmay be included in the drill stringand are constructed and intended to be heavy to apply weight on the drill bitto assist the drilling process. Because of the thickness of the collar's wall, pocket-type cutouts or other type recesses may be provided into the collar's wall without negatively impacting the integrity (strength, rigidity, and the like) of the collaras a component of the drill string.

is a diagram of an example downhole environment having tubulars in accordance with various aspects of the disclosure. In some aspects, an example systemis depicted for conducting downhole measurements after at least a portion of a wellbore has been drilled and the drill string removed from the well. A downhole tool is shown having a tool bodyto perform logging, measurements, and/or other operations. For example, instead of using the drill stringofto lower a tool body, which may contain sensors and/or other instrumentation for detecting and logging nearby characteristics and conditions of the wellboreand surrounding formations, a wireline conveyancemay be used.

The tool bodymay be lowered into the wellboreby wireline conveyance. The wireline conveyancemay be anchored in the drill rigor by a portable device such as a truck. The wireline conveyancemay include one or more wires, slicklines, cables, and/or the like, as well as tubular conveyances such as coiled tubing, joint tubing, or other tubulars.

The wireline conveyanceprovides power and support for the tool, as well as enabling communication between processing systemson the surface. In some examples, the wireline conveyancemay include electrical and/or fiber optic cabling for performing any communications. The wireline conveyanceis sufficiently strong and flexible to tether the tool bodythrough the wellbore, while also permitting communication through the wireline conveyanceto one or more of the processing systems, which may include local and/or remote processors. In some cases, power may be supplied via the wireline conveyanceto meet the power requirements of the tool. For slickline or coiled tubing configurations, power may be supplied downhole with a battery or via a downhole generator.

In other examples, as illustrated in, the systemcan be employed in an exemplary wellbore environment. The environment includes a derrickextending over and around a fluidic channel, such as a wellborein.

A conduitcan be disposed within the wellbore. In at least one example, the fluidic channelcan include the conduit. The conduitcan include, for example, wireline conveyance(shown in), tubing-conveyed, wireline, slickline, work string, joint tubing, jointed pipe, pipeline, coiled tubing, and/or any other suitable means for conveying a downhole device, e.g., tool bodyin, into a fluidic channel, such as a wellbore. In some examples, the conduitcan include electrical and/or fiber optic cabling for carrying out communications. The conduitcan be sufficiently strong and flexible to tether the downhole device, e.g., tool bodyin, through the wellbore, while also permitting communication through the conduitto one or more of processors, which can include local and/or remote processors. Moreover, power can be supplied via the conduitto meet power requirements of the downhole device, e.g., tool bodyin. For slickline or coiled tubing configurations, power can be supplied downhole with a battery or via a downhole generator.

The system ofincludes a data acquisition system. Data acquisition systemincludes at least one sensorcommunicatively coupled with the controllerwhich can receive and/or process the data received from the sensors. Whileillustrates one sensor, in other examples, more than one sensormay be utilized. In at least one example, as illustrated in, at least one sensorcan be disposed within the wellboreat predetermined locations. The sensoris positioned to measure pressure in the wellbore. Additionally, the sensormay measure parameters related to the wellboreand/or fluid in the wellbore, such as flow rate, temperature, and/or composition. In some examples, additional sensorsmay measure additional parameters related to the wellboreand/or the fluid in the wellboresuch as flow rate, temperature, and/or composition. In at least one example, sensorcan be disposed within the wellbore, for example it may be coupled with or disposed in a casing of the wellbore. Similarly, if the configuration included fluid transportation between two storage and refinery, for example, the at least one 150 can be along the flowline transporting the fluid.

It should be noted that whilegenerally depicts a land-based operation, the principles described herein are equally applicable to operations that employ floating or sea-based platforms and rigs, without departing from the scope of the disclosure. Also, even thoughdepicts a vertical wellbore, the present disclosure is equally well-suited for use in wellbores having other orientations, including horizontal wellbores, slanted wellbores, multilateral wellbores, or the like.

The fluidic channelcan include open ends such that each end is accessible by an operator and fluid can flow through the open ends. In other examples, the fluidic channelcan include a closed end such that fluid cannot flow through closed end. In at least one example, the open and/or closed ends can be located along any point of the fluidic channel. For example, an open and/or closed end may be located in the middle of the fluidic channel, and may be an entry point to gain access to the fluidic channel. Whileshows a vertically oriented fluidic channel, the fluidic channelcan include multiple orientations, for example a vertical section, a diagonal section, and/or a horizontal section. In other examples, the fluidic channelcan extend only in one direction or multiple directions along any axis.

The fluidic channelhas walls which form an interior passage through which fluid can be contained in and flow. The fluid can be one fluid or more than one fluid. The fluid can include, for example, water and/or oil. The fluid can also substantially fill the entire fluidic channelor, in other examples, the fluid can partially fill the fluidic channel. The fluidic channelcan be substantially circular, ovoid, rectangular, or any other suitable shape. The walls of the fluidic channelcan be made of any combination of plastics or metals, suitable to withstand fluid flow without corrosion and with minimal deformation. The fluidic channelcan also include at least one portof. The portofcan extend through the walls of the fluidic channeland permit communication across the walls of the fluidic channel.

One example of a device that can be inserted and removed from the fluidic channel, through a portofor an open end of a pipe is a PIG device, either automated or manual. PIG devices are particularly useful with the substance of this disclosure as the predictive model identified hereinbelow is able to identify the location of the deposit and track its build-up over time. The operators of the system are then able to more easily determine when a cleanout is needed and the closest port or opening to the deposit for easy insertion of the PIG device. The predictive model can also provide a quick and meaningful test to determine if the clean-out was successful and to track how often successful clean-outs are needed.

The systemincludes a data acquisition systemwhich receives and processes data such that the data can be used and interpreted by a user. The data acquisition systemcan be located on-site and can share data with a data center, which can be proximate to the end of the fluidic channel. The data center may be above ground, under water, underground, or located at any point to collect data. For example, the data center may be an underwater vehicle or on a platform.

To obtain the measured profile and inspect the fluidic channelin a non-intrusive manner, at least one pressure pulse can be induced. Referring to, to induce the pressure pulses, a pressure devicecan be used. The pressure devicecan be actuated to create a pressure pulse that travels through the fluidic channelat the local speed of sound in the medium. In at least one example, the pressure deviceis not a permanent fixture or attachment. As such, the pressure devicecan be coupled to the fluidic channelonly when needed to create pressure pulses. In other examples, the pressure devicecan be a permanent fixture in the fluidic channel. In at least one example, the pressure devicecan include a valve which can close to create a pressure pulse, an injector to inject fluid into a fluidic channel, and/or a hydrophone projector. The type of mechanism for the pressure deviceto create the pressure pulse can be determined based on the type of fluid and/or the type of fluidic channel.

For example, as illustrated in, a pipeline or flowline systemcan include a pressure device, and the pressure devicecan include a hydrophone projector, and can include at least one hammerand a collarcoupled with the hammer. The collarcan be configured to couple externally with the walls of the fluidic channel. The collar, for example, can wrap around the walls of the fluidic channelto secure the pressure deviceto be in contact with and external of the fluidic channel. As such, to actuate a pressure pulse with the pressure device, the pressure deviceis not deposited within the interior passage of the fluidic channel. The pressure deviceis non-intrusive, as the pressure deviceis positioned external to the fluidic channel.

The pressure devicecan be actuated and create the pressure pulse by the at least one hammerstriking and impacting the external surface of wallsof the fluidic channel. The hammercan be electrical, mechanical, pneumatic, and/or hydraulic hammers. The hammercan be any suitable object which can strike and impact the external surface of the walls, thereby creating a pressure pulse within the fluidic channel. For example, the hammercan be any blunt object which does not damage the wallsof the fluidic channelas the hammerimpact the walls. When the hammerstrike the walls, an acoustic pressure pulse is generated that travels upstream of the pressure device. The pressure devicecan be electrically programmed, such that different pressures can be induced based on the strikes of the hammer. The harder the impact of the hammeragainst the walls, the greater, or sharper, the pressure pulse. The striking of the hammeragainst the wallsprovides for a pulse with a higher resolution.

As the pressure pulse travels along the fluidic channel, any encountered obstructions or depositsgenerate a reflected signal which is reflected back toward the pressure device. The systemincludes a sensorto receive the reflected pressure pulse signals. The sensorcan be a known distance from the pressure device. The sensorcan be a pressure transducer. In other examples, the sensorcan be any suitable sensor that measures pressure or stress of the fluid, for example a string gauge or an optical fiber transducer. The sensorcan be disposed within the interior passage of the fluidic channel. For example, the sensor, as illustrated in, can be mounted to and/or inserted through a portof the fluidic channel. The portmay be pre-existing, so the fluidic channeldoes not need to be modified or disrupted to position the sensor. In other examples, the sensorcan be disposed external to the fluidic channel.

The reflected signals received by the sensorare passed through a transmission systemto a data acquisition systemto be interpreted to map out and quantify any depositsin the fluidic channel. The data acquisition systemcan be located at the surface, within a vehicle, or any other suitable location such that the data can be interpreted by an operator. The transmission systemcan be wireline, optical fiber, wirelessly such as through the cloud or Bluetooth, or any other suitable method to transmit data. In at least one example, the transmission systemcan additionally be coupled with the pressure deviceto send/receive instructions and/or data from the pressure device.

illustrates a non-intrusive deposition measurement system, which measures the aforementioned results of drilling, wireline, or pumping operations. Non-intrusive deposition measurement system, shown in, can be a part of a pipeline, a producing wellbore, flowlines, or any pipeline where it is useful to measure depositions in a non-intrusive manner, e.g., single-phase and multi-phase fluids in the petroleum industry or any related industry, as shown in. Further, while, places all the components on site, the components are capable of being separate and connected through a network. The non-intrusive deposition measurement systemworks via the principle that a sensor can measure pressure profiles which can be compared with expected or predicted pressure profiles. Expected pressure profiles have normal distribution about the inner diameter of a pipe, but if there are any deposits within the pipe, the pressure profile will change based on the impact of the deposition. This pressure profile change is measured by sensorand can be analyzed by the predictive model, which identifies the differences between the expected pressure profile and the measured pressure profile. This difference allows the system to identify the presence of depositions.

includes sensorthat, in one embodiment, can be connected to a pipeline that is fluidically connected to a source of hydrocarbons such as a producing well or hydrocarbon storage area such as a tank farm or other hydrocarbon storage media. Sensormeasures the pressure profile provided by a signal based on a signal generator disposed on or within pipeline. Signal generator may be operable to produce an acoustical or pressure signal within pipeline which may propagate through pipeline and the signal produced can be received by sensor. Acoustical or pressure signals may interact with deposits which may alter acoustical or pressure signal by altering the amplitude, phase, frequency, or any combination thereof of acoustical or pressure signal created by the signal generator. In smooth conduits with no deposits, returning signals may be relatively unchanged. Conversely, when deposits are present, returning signals may exhibit additional characteristics different from the generated signal. Friction factors associated with deposits may determine how and to what degree acoustical or pressure signals are altered when encountering deposits. Reflected signals may be used to determine the location and magnitude of a deposit, for example.

Sensormay be disposed on or within a pipeline at an upstream or downstream location from a signal generator. Sensor, and/or sensorin, may be operable to detect acoustical or pressure signals produced by the signal generator or returning signals. Returning signals may be reflected acoustical or pressure waves reflected by deposits or other features within pipeline. Signals collected by Sensormay be converted to a data file or data stream and transmitted to predictive modelvia the analog-to-digital converter. The analog-to-digital convertermay be any module or program capable of converting the raw data received by the sensorinto a digital signal that is compatible with predictive model. Transmission of the raw data to analog-to-digital converterand the data file or data stream from the analog-to-digital converterto the predictive modelmay be wired or wireless, for example.

The sensorwill typically encounter a pressure pulse traveling in a wellbore created by, e.g., a water hammer or valve closing. In principle, it can be assumed that when the pressure pulse has reached the bottom of the well or end of the pipe, the fluid velocity in the wellbore will be effectively reduced to zero. The frictional pressure drop will propagate continuously to the wellhead and can be measured and is often called line-packing.

One method of calculating the effects of the pressure pulse is using the Darcy-Weisbach equation, an empirical formula used to calculate the pressure drop in a fluid flowing through a pipe or duct. This equation is commonly used in fluid mechanics and engineering, particularly in fluid flow analysis in pipelines. The Darcy-Weisbach equation can be expressed as follows:

Where Δp is the pressure drop (head loss) in the pipe, f is the Darcy friction factor, a dimensionless parameter that depends on the pipe's roughness and the Reynolds number (Re) of the flow, L is the length of the pipe, d is the diameter of the pipe, ρ is the density of the fluid, and v is the velocity of the fluid flow. This equation can be used to estimate the pressure drop due to friction as a fluid flows through a pipe, and it is particularly valuable in designing and analyzing pipelines for various applications, including water supply, oil and gas transportation, and industrial processes. The Darcy-Weisbach equation can also be written in terms of the pressure gradient if desired.

The friction factor in single-phase and multiphase flows can be obtained from semi-empirical relationships such as the Blasius equation for laminar flow or the Colebrook-White equation, depending on the smoothness of the pipe. These equations show that the flow in land-based and offshore wellbores, flowlines, and pipelines depends on many factors. Additional factors are the pressure, volume, and temperature behavior of the fluid mixtures involved.

Sensorcan be used to collect and/or analyze multiple types of data, including:

The multiple types of data referenced above can be captured using a single pressure transducer or multiple pressure transducers, can include the flowline geometry, and can include the fluid properties known to the system or collected by the sensor. Also, some of the data collected by the sensoris used to calculate the above data, and all of the data collected or calculated can be stored in a dataset.

For example, the pressure transducer measures the pressure of the fluid within a pipeline or flowline. By capturing pressure data at different points or continuously, the system is able to collect data associated with various aspects of the fluid flow within the pipeline or flowline, such as flow rate, velocity, and pressure drops along the pipeline.

The flowline geometry is either modeled or known to the system operator and addresses the physical dimensions and shape of the pipeline or flowline, including data that addresses pipe diameter, pipe length, and any bends and/or fittings encountered in the pipeline or flowline. With the flowline geometry, the system is able to calculate flow rates and measure the fluid dynamics changes along the flowline that can be caused by, for example, changes in pipe diameter or the presence of deposits or other obstacles.

Fluid properties include such parameters as fluid density, fluid viscosity, fluid temperature, and other characteristics of the fluid within the pipeline or flowline. Fluid properties allow for the system to calculate and model fluid behavior under various conditions encountered during the transportation of the fluid through the pipeline or flowline. For example, when the system has data related to the fluid's viscosity, the system can better predict how the fluid will resist flow, and having data related to density can allow the system to convert between volumetric flow rates and mass flow rates. In one exemplary environment, the systemis able to use each of these measurements alone and/or in combination to model different aspects of the fluid flow through the pipeline or flowline.

These measurements and model outputs can all be stored in a dataset and used with the predictive model. Similarly, the legacy data is also capable of including any or all of these measurements in a dataset for use as a baseline for the predictive model. The non-intrusive deposition measurement systemis also able to determine segments of the pipeline or flowline based on the behavior of the measurements and models through the pipeline or flowline. When there are behavior changes within the pipeline or flowline, it can be advantageous to segment the pipeline or flowline into different segments so that the predictive model is better able to fit, as described with respect tobelow, the predictive model to the pipeline or flowline, thereby providing improved outcomes for that segment of the pipeline or flowline.