Method and system for moisture content sensing in oil-water stream

Abstract

A method (300) for moisture content sensing in an oil-water stream includes obtaining a complex absorption spectrum of the oil-water stream, obtaining a reference absorption spectrum of a reference fluid, calculating a slope (400) of a data point associated with the complex absorption spectrum of the oil-water stream relative to a corresponding data point associated with a reference absorption spectrum of a known fluid, and determining a moisture content of the oil-water stream based on the slope (400).

Description

Background Art

[0001] To meet the world's growing energy demands, efficient oil production is indispensable. Methods for enhanced oil recovery and perforated rocks present near the reservoir may be the reasons for water mixing into the oil. Water cut (WC) measurement is crucial in the oil industry as it is key for production allocation, reservoir management, and early water breakthrough detection. WC varies with the age and geographical location of the oil well, which requires WC sensors to cover almost the full dynamic range (0 - 100%) to cover a wide range of industrial applications. There are a large number of WC sensors based on various technologies in the literature. The dielectric properties of the oil - water (OW) mixture, especially at high frequencies (MHz), have been utilized to detect WC by measuring microwave resonance and transmission. However, the sensitivity of microwave resonance to WC is poor, and microwave transmission is interfered with in saline OW mixtures. WC can be measured invasively by several methods, but these methods cannot be used for online WC sensing. Multi - energy gamma rays using radioactive sources can also be employed, but they involve handling and disposal safety issues. Planar microwave resonance has been implemented on the pipe surface to provide in - situ, non - invasive WC sensing. However, calibration is required to know which oils are present in the OW flow. Based on the modified Beer - Lambert law, near - infrared (NIR) spectroscopy has been used for non - homogeneous immiscible mixtures. Although the resulting WC sensors have been proven to be more accurate than other sensors, they require frequent well - specific calibrations, which become cumbersome as the well ages and the geographical location changes. Therefore, an alternative WC sensor that operates over the full dynamic range (0 - 100%) and does not require any calibration would be highly desirable and beneficial. Summary of the Invention

[0002] This Summary of the Invention is provided to introduce a series of concepts that will be further described in the Detailed Description below. This Summary of the Invention is not intended to identify key or essential features of the claimed subject matter nor is it intended to be used to limit the scope of the claimed subject matter.

[0003] Generally, in one aspect, embodiments relate to a method for water - cut sensing in an oil - water flow, the method comprising: obtaining a composite absorption spectrum of the oil - water flow; obtaining a reference absorption spectrum of a reference fluid; calculating a slope of data points associated with the composite absorption spectrum of the oil - water flow relative to corresponding data points associated with the reference absorption spectrum of a known fluid; and determining the water - cut of the oil - water flow based on the slope.

[0004] Generally, in one aspect, an embodiment relates to a system for water content sensing in an oil-water flow, the system comprising: a laser-based spectral sensor; and a computer system that: obtains a composite absorption spectrum of the oil-water flow from the laser-based spectral sensor, obtains a reference absorption spectrum of a reference fluid, calculates a slope of data points associated with the composite absorption spectrum of the oil-water flow relative to corresponding data points associated with the reference absorption spectrum of a known fluid, and determines a water content in the oil-water flow based on the slope.

[0005] Generally, in one aspect, an embodiment relates to a non-transitory machine-readable medium including a plurality of machine-readable instructions executable by one or more processors, the plurality of machine-readable instructions causing the one or more processors to perform operations including: obtaining a composite absorption spectrum of the oil-water flow; obtaining a reference absorption spectrum of a reference fluid; calculating a slope of data points associated with the composite absorption spectrum of the oil-water flow relative to corresponding data points associated with the reference absorption spectrum of a known fluid; and determining a water content of the oil-water flow based on the slope.

[0006] According to the above structures and functions, embodiments of the present disclosure may include corresponding apparatuses adapted to perform the various steps and functions defined above according to any one of one or more aspects and embodiments of the one or more aspects described in the present disclosure.

[0007] Other aspects and advantages of the claimed subject matter will become apparent from the following description and the appended claims. BRIEF DESCRIPTION OF THE DRAWINGS

[0008] Specific embodiments of the disclosed technology will now be described in detail with reference to the drawings. For consistency, like elements in the various drawings are denoted by like reference numerals.

[0009] Figure 1 A well environment according to one or more embodiments is shown.

[0010] Figure 2A and Figure 2B A system for water content sensing in an oil-water flow according to one or more embodiments is shown.

[0011] Figure 3 A flowchart of a method according to one or more embodiments is shown.

[0012] Figure 4 An example of slopes before and after outlier removal according to one or more embodiments is shown.

[0013] Figure 5 A performance example according to one or more embodiments is shown.

[0014] Figure 6 A computer system according to one or more embodiments is shown. DETAILED DESCRIPTION

[0015] In the following detailed description of embodiments of the present disclosure, numerous specific details are set forth in order to provide a more thorough understanding of the present disclosure. However, it will be apparent to one of ordinary skill in the art that the present disclosure 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.

[0016] Throughout the application, ordinal numbers (e.g., first, second, third, etc.) may be used as adjectives for elements (i.e., any nouns in the present application). Unless explicitly stated, such as by using terms like "before," "after," "single," and other such terms, the use of ordinal numbers does not imply or create any particular order of the elements, nor does it limit any element to only a single element. Instead, the use of ordinal numbers is for differentiating between elements. As an example, a first element is different from a second element, and the first element may contain more than one element and may come after (or before) the second element in the ordering of the elements.

[0017] Water cut (WC) measurement is crucial in the oil industry as it is key for production allocation, reservoir management, and early water breakthrough detection. WC varies with the age and geographical location of oil wells, which requires WC sensors to cover almost the full dynamic range (0 - 100%), thus covering a wide range of industrial applications.

[0018] Generally, embodiments of the present disclosure include systems and methods for WC sensing in oil - water flows. The following discussion provides a description of scenarios that require or benefit from the availability of accurate WC measurement values and then describes the components of systems for WC sensing and the operations performed by these systems.

[0019] Figure 1 A schematic diagram according to one or more embodiments is shown. Figure 1The well environment 100 is shown, which includes a hydrocarbon reservoir (“reservoir”) 102 located in a subterranean hydrocarbon-bearing formation 104 and a well system 106. The hydrocarbon-bearing formation 104 may include porous or fractured rock formations located underground (beneath the Earth's surface (“ground”) 108). In the case where the well system 106 is a hydrocarbon well, the reservoir 102 may include a portion of the hydrocarbon-bearing formation 104. The hydrocarbon-bearing formation 104 and the reservoir 102 may include different rock layers having different properties (such as different degrees of permeability, porosity, and resistivity). In the case where the well system 106 operates as a production well, the well system 106 may facilitate the extraction of hydrocarbons (or “products”) from the reservoir 102. In the case where the well system 106 operates as an injection well, the well system 106 may be used in enhanced oil recovery methods to displace the produced hydrocarbons and / or maintain the pressure distribution in the reservoir 102.

[0020] In some embodiments, the well system 106 includes a wellbore 120, a downhole well system 122, a surface well system 124, and a data acquisition system 126. The data acquisition system 126 may monitor and / or control various operations of the well system 106, such as well production operations, well completion operations, well maintenance operations, and reservoir monitoring, evaluation, and development operations. In some embodiments, the data acquisition system 126 includes a computer system that is the same as or similar to the computer system 602 described in Figure 6 and the accompanying description.

[0021] The wellbore 120 may include a borehole extending from the ground 108 into a target area (such as the reservoir 102) of the hydrocarbon-bearing formation 104. The upper end of the wellbore 120 that terminates at or near the ground 108 may be referred to as the “surface” end of the wellbore 120, while the lower end of the wellbore that terminates in the hydrocarbon-bearing formation 104 may be referred to as the “downhole” end of the wellbore 120. The wellbore 120 may facilitate the circulation of drilling fluid during drilling operations, the flow of hydrocarbon products (“products”) 121 (such as oil and gas) from the reservoir 102 to the ground 108 during production operations, the injection of substances (such as water) into the hydrocarbon-bearing formation 104 or the reservoir 102 during injection operations, or the communication of monitoring equipment (such as logging tools) placed in the formation 104 or the reservoir 102 during monitoring operations (such as in-situ logging operations).

[0022] In some embodiments, during the operation of well system 106, data acquisition system 126 collects and records wellhead data 140 of well system 106 and other data regarding downhole equipment and downhole sensors. Wellhead data 140 may include, for example, measurements of wellhead pressure (P) (e.g., including flowing wellhead pressure (FWHP)), wellhead temperature (T) (e.g., including flowing wellhead temperature), wellhead productivity (R), and / or water cut (WC) data during part or all of the life of well 106. In some embodiments, the measurements are recorded in real time and are available for viewing or use within seconds, minutes, or hours of sensing the condition (e.g., the measurements are available within 1 hour of sensing the condition). In such embodiments, wellhead data 140 may be referred to as “real-time” wellhead data 140. Real-time wellhead data 140 may enable the operator of the well to evaluate the relative current state of well system 106 and make real-time decisions regarding the development of well system 106 and reservoir 102, such as adjusting the production flow from the well or the injection flow into the well as needed.

[0023] In some embodiments, well surface system 124 includes wellhead 130. Wellhead 130 may include a rigid structure mounted at the “uphole” end of wellbore 120, at or near where wellbore 120 terminates at earth surface 108. Wellhead 130 may include structures for supporting (or “hanging”) casing and production tubing extending into wellbore 120. Product 121 may flow through wellhead 130 after leaving wellbore 120 and well downhole system 122 (including, for example, casing and production tubing). In some embodiments, well surface system 124 includes flow control equipment operable to control the flow of substances into and out of wellbore 120. For example, well surface system 124 may include one or more choke valves 132 operable to control the flow of product 121.

[0024] Continuing to refer Figure 1 to, in some embodiments, well surface system 124 includes surface sensing system 134. Surface sensing system 134 may include sensor devices for sensing the properties of substances (including product 121) passing through or otherwise located within well surface system 124. These properties may include, for example, the pressure, temperature, and flow rate of product 121 flowing through wellhead 130 or other conduits of well surface system 124 after flowing out of wellbore 120.

[0025] In some embodiments, well intervention operations can also be performed at the wellsite. For example, well intervention operations can include various operations (e.g., fracturing operations, CT, flowback, separators, pumping, wellhead and christmas tree maintenance, wireline, braided cable, coiled tubing, snubbing, workover, subsea well intervention, etc.) performed by one or more service entities on an oil well or a gas well during the production life of the oil well or the gas well. For example, well intervention activities can be similar to completion operations, well conveyance operations, and / or drilling operations in order to modify the state or the geometry of the well. In some embodiments, well intervention operations are used to provide well diagnostics and / or manage the production of the well.

[0026] In one or more embodiments, well system 106 also includes a system (not shown) for WC sensing. As previously described, WC measurements can be used for purposes such as production allocation, reservoir management, early water breakthrough detection, etc. The system for WC sensing will be discussed subsequently with reference to the remaining figures.

[0027] Although Figure 1 various configurations of hardware components and / or software components are shown, other configurations can be used without departing from the scope of the present disclosure. For example, Figure 1 the various components in can be combined to create a single component. As another example, functions performed by a single component can be performed by two or more components.

[0028] Figure 2A and Figure 2B Systems 200, 250 for water cut sensing in an oil-water flow are shown in accordance with one or more embodiments. The systems 200, 250 implement laser-based absorption spectroscopy and operate in the near-infrared (NIR) range to perform accurate water detection over a full dynamic range (0 - 100% water cut) and can be used without calibration.

[0029] Systems 200, 250 according to embodiments of the present disclosure use NIR spectroscopy to measure WC and rely on water having strong absorption lines in the infrared (IR) wavelength region. An example of an absorbance record of NIR spectroscopy for water is shown, and examples of absorbance records of octane, methanol, isopropyl alcohol, silicone oil, and ethanol, which can be considered representative species of oil, are also shown. In one or more embodiments, the range of 4500 cm -1 to 7500 cm -1 (about 1300 nm to 2200 nm) is used to measure the entire water concentration range (0 - 100%) with minimal oil interference. For example, for water concentrations below 10%, the peak near 1900 nm (5210 cm -1 to 5270 cm -1 ) can be analyzed, while for 1400 nm (7140 cm -1 to 7200 cm -1Lower peaks in the vicinity can be used to measure higher concentrations.

[0030] As Figure 2A and Figure 2B shown, a quartz flow cell can be used to circulate an oil-water mixture. NIR spectroscopy is performed through the quartz flow cell. The oil-water mixture can be obtained from a well environment as previously described.

[0031] System 200 includes three lasers, while system 250 includes six lasers. Each laser is capable of scanning a spectral range of 20 cm -1 in extent.

[0032] More specifically, in system 200, three fiber-coupled quantum cascade lasers (QCLs) (e.g., Nanoplus QCLs) emitting near 1.4 μm and having an output power of, for example, approximately 10 mW are combined using a fiber combiner and collimated towards the target OW mixture to expose the OW mixture to the incident signal. Fibers can be used to transmit the incident signal from the lasers to the water-oil flow in the tube of the quartz flow cell and from the tube to a photodetector. Driven by a laser controller, the lasers can be scanned at a frequency of 50 Hz to scan a tuning range of 7140 cm -1 to 7200 cm -1 in extent. A pump (e.g., a 20 W DC-powered pump) can be used to circulate the OW mixture through a quartz flow cell with a 1 mm sampling length. The transmitted signal can be collected by a photodetector (e.g., a DC-coupled, TE-cooled photodetector with a bandwidth of 25 MHz, provided by Thorlabs). In one embodiment, an 83 mm silica etalon is used to convert the scan time to wavenumber. The NIR spectral data obtained from the detector can be processed by a computer system, as further discussed below. Additionally, the NIR spectral data can be visualized using, for example, an oscilloscope.

[0033] In system 250, while generally similar to system 200, three distributed feedback (DFB) lasers (e.g., Nanoplus DFB lasers) are used to scan a spectral range of 7140 cm -1 to 7200 cm -1 in extent, and three additional lasers are used to scan a range of 5210 cm -1 to 5270 cm -1 in extent. In one embodiment, the sampling length is 1 mm. Other sampling lengths can be used. For example, to detect low concentration measurements, the laser can be propagated through a 3 mm section to increase the absorbance of water and thus reduce errors.

[0034] Although Figure 2A andFigure 2B A particular configuration of the system is shown, but variants of these systems can be used without departing from the present disclosure. For example, the various optical elements can be arranged in different ways, and different and / or additional optical elements can be used without departing from the present disclosure. For example, any number and any type of lasers can be used, the sampling length can vary, etc.

[0035] Figure 3 A method for water content sensing in an oil-water flow according to one or more embodiments is shown. The method can determine the water content in the oil-water flow without the need for calibration or knowledge of the type of oil in the oil-water flow. Briefly, the algorithm reduces or minimizes the effect of interfering absorbance to isolate the absorbance of water, thereby accurately predicting the water content without prior calibration. As described later, calibration-free WC sensing is achieved by identifying and eliminating the interference of non-water (e.g., oil) species in the oil-water flow. More specifically, the slope of the data points of the absorbance obtained for the composite absorption spectrum of the oil-water flow relative to the corresponding data points obtained for the absorption spectrum of a reference fluid (e.g., water) is calculated, and a fitting algorithm is applied to eliminate the effect of non-water (e.g., oil) species on the slope. The slope itself can indicate the concentration of water.

[0036] The method can be implemented using instructions stored on a non-transitory medium, which can be executed by a computer system as shown in Figure 6 shown.

[0037] Although Figure 3 the individual blocks in

[0038] are presented and described in sequence, those skilled in the art will understand that some or all of these blocks can be executed in a different order, can be combined or omitted, and some or all of these blocks can be executed in parallel. In addition, these blocks can be executed actively or passively.

[0038] In step 302, a composite absorption spectrum of the oil-water flow is obtained. The composite absorption spectrum can be obtained using the system shown in Figure 2A and Figure 2B shown. Briefly, the laser signal propagates through the oil-water flow and is collected by a photodetector. The Beer-Lambert law is used to quantify the composite absorbance (over the entire spectrum) based on the attenuation of the laser intensity. The composite absorbance is the result of the absorbance of water and / or oil in the oil-water flow.

[0039] In step 304, data points of the first derivative of the composite absorption spectrum of the oil-water flow are obtained. The first derivative can be calculated between consecutive wavelength intervals. Any method for calculating the derivative can be used.

[0040] In step 306, a reference absorption spectrum of a reference fluid is obtained. The reference fluid can be water, and the reference absorption spectrum can be obtained from a database.

[0041] In step 308, data points of the first derivative of the absorption spectrum of water are obtained. The first derivative can be calculated between consecutive wavelength intervals. Any method for calculating the derivative can be used.

[0042] In step 310, the slope of the data points of the first derivative of the composite absorption spectrum with respect to the corresponding data points of the first derivative of the reference absorption spectrum is calculated. This slope can be calculated by performing a linear fit. Figure 4 An example of performing step 310 is provided in the left panel, which shows the data points plotted in a 2D space and the linear fit line.

[0043] In step 312, the slope is recalculated. First, a threshold distance can be defined to eliminate outliers in the data points of the first derivative of the composite absorption spectrum. This distance can be any distance from the linear fit line (e.g., Euclidean distance). The threshold distance can be determined by experiment or simulation. Specifically, the method of Figure 3 can be performed using different threshold distances, and the threshold distance that provides the best (most accurate water content prediction) result can be selected for use. Next, the threshold distance is used to determine the outliers in the 2D space. Data points beyond the threshold distance are eliminated from further fitting or calculation. After removing the outliers, the slope is recalculated. Examples of calculating the slope before and after outlier removal are discussed below with reference to Figure 4 The left panel of Figure 4 shows the slope calculation before outlier removal, Figure 4 and the right panel of

[0044] shows the slope calculation after outlier removal.

[0045] The above steps can be performed for different wavelengths / wavenumbers. As shown in the spectrum included in Figure 2A the absorbance of water includes a weaker peak around 7150 cm -1 and a stronger peak around 5250 cm -1Stronger peaks nearby. The former can be used to measure high water content, and the latter can be used to measure low water content. The advantage of using different peaks for different water contents is that it allows the absorbance to be kept within a certain range (e.g., 0.01 to 3.5) to achieve a better signal-to-noise ratio. Therefore, depending on the prevailing water content, the calculations of the slope and the outlier-adjusted slope can be based on different regions of the absorption spectrum. Thus, based on this consideration, an appropriate wavenumber interval can be selected from the complete absorption spectrum. In an embodiment of this method, an "if" statement can be used to automate the above selection. First, the region at the stronger peak can be used to calculate the water content. If the obtained reading is below 10%, the reading is assumed to be accurate. However, if the reading is above 10%, the method can be repeated for the region at the weaker peak.

[0046] The steps of the method can be repeated over time, for example, in a loop. Thus, the described system and method can continuously provide updated readings on the water content in the oil-water flow.

[0047] Figure 4 Shows an example 400 of the slope before and after outlier removal calculated using the Figure 3 method. Figure 4 The graph in the left panel shows the slope generated in the presence of outliers. This slope can be obtained by performing Figure 3 the steps 310 of the method described in Figure 4 The graph in the right panel shows the outlier-adjusted slope after outlier removal. This outlier-adjusted slope can be obtained by performing Figure 3 the steps 312 of the method described in

[0048] Figure 5 Shows a performance example 500. Figure 5 The graph in the left panel shows the measured absorption spectrum obtained for an oil-water mixture (where the water content ranges from 0% to 100%) and compared with the simulated pure water spectrum. Figure 5 The graph in the right panel shows the residual error in the comparison between the measured water content and the actual water content. As shown, the residuals remain within the range of + / - 5%.

[0049] Embodiments of the present disclosure have various beneficial features. For example, embodiments of the present disclosure provide accurate sensing of the water content in an oil-water flow without calibration and without knowledge of the types of substances present in the oil-water flow. Embodiments of the present disclosure are highly resistant to signal attenuation caused by laser scattering due to particles, salinity effects, and high-temperature effects.

[0050] Embodiments can be implemented on a computer system. Figure 6FIG. 602 is a block diagram of a computer system 602 for providing computing functionality associated with algorithms, methods, functions, procedures, flows, and programs as described in the present disclosure. The illustrated computer 602 is intended to encompass any computing device, such as a high-performance computing (HPC) device, a server, a desktop computer, a laptop / notebook computer, a wireless data port, a smart phone, a personal data assistant (PDA), a tablet computing device, one or more processors within these devices, or any other suitable processing device, including physical or virtual instances of computing devices (or both). Additionally, computer 602 may include a computer that includes: an input device, such as a keypad, a keyboard, a touch screen, or other device that accepts user information; and an output device that conveys information associated with the operation of computer 602, the information including digital data, visual or audio information (or a combination of information); or a GUI.

[0051] Computer 602 may act in the role of a client, a network component, a server, a database, or other persistency, or any other component in a computer system for performing the subject matter described in the present disclosure (or a combination of roles). The illustrated computer 602 is communicatively coupled to network 630. In certain embodiments, one or more components of computer 602 may be configured to operate within an environment including a cloud-based environment, a local environment, a global environment, or other environment (or a combination of environments).

[0052] At a high level, computer 602 is an electronic computing device capable of operating to receive, transmit, process, store, or manage data and information associated with the described subject matter. According to certain embodiments, computer 602 may also include an application server, an email server, a web server, a cache server, a streaming data server, a business intelligence (BI) server, or other servers (or a combination of servers), or be communicatively coupled to the various servers described above.

[0053] Computer 602 may receive requests from client applications (e.g., executing on another computer 602) via network 630 and respond to the requests by processing the received requests in a suitable software application. Additionally, requests may also be sent to computer 602 from internal users (e.g., from a command console or via other suitable access methods), external or third parties, other automated applications, and any other suitable entity, individual, system, or computer.

[0054] Each component of computer 602 can communicate using system bus 603. In some embodiments, any or all components of computer 602 (hardware or software (or a combination of hardware and software)) can interact with each other or with interface 604 (or a combination of both) on system bus 603 using application programming interface (API) 612 or service layer 613 (or a combination of API 612 and service layer 613). API 612 can include descriptions of routines, data structures, and object classes. API 612 can be independent of or dependent on a computer language and refers to a complete interface, a single function, or even a group of APIs. Service layer 613 provides software services to computer 602 or other components (whether shown or not) communicatively coupled to computer 602. The functionality of computer 602 can be accessible to all service consumers using the service layer. Software services (such as those provided by service layer 613) provide reusable, defined business functionality through defined interfaces. For example, the interface can be software written in JAVA, C++, or other suitable languages that provide data in extensible markup language (XML) format or other suitable formats. Although shown as an integrated component of computer 602, alternative embodiments can show API 612 or service layer 613 as separate components relative to other components of computer 602 or other components (whether shown or not) communicatively coupled to computer 602. Additionally, any part or all of API 612 or service layer 613 can be implemented as a sub-module or sub-module of another software module, an enterprise application, or a hardware module without departing from the scope of the present disclosure.

[0055] Computer 602 includes interface 604. Although shown as a single interface 604 in Figure 6 two or more interfaces 604 can be used according to specific needs, expectations, or specific embodiments of computer 602. Interface 604 is used by computer 602 to communicate with other systems in a distributed environment connected to network 630. Generally speaking, interface 604 includes logic encoded in software or hardware (or a combination of software and hardware) and operable to communicate with network 630. More specifically, interface 604 can include software that supports one or more communication protocols associated with communication so that network 630 or the hardware of the interface is operable to communicate physical signals inside and outside the shown computer 602.

[0056] Computer 602 includes at least one computer processor 605. Although in Figure 6is shown as a single computer processor 605 in, but two or more processors may be used depending on particular needs, desires, or particular implementations of the computer 602. Generally, the computer processor 605 executes instructions and manipulates data to perform the operations of the computer 602 and any algorithms, methods, functions, procedures, processes, and programs as described in this disclosure.

[0057] The computer 602 also includes a memory 606 that stores data for the computer 602 or other components (or a combination of both) that may be connected to the network 630. For example, the memory 606 may be a database that stores data consistent with this disclosure. Although shown as a single memory 606 in, Figure 6 two or more memories may be used depending on particular needs, desires, or particular implementations of the computer 602 and the functionality described. Although the memory 606 is shown as an integrated component of the computer 602, in an alternative implementation, the memory 606 may be external to the computer 602.

[0058] The application 607 is an algorithmic software engine that provides functionality (particularly with respect to the functionality described in this disclosure) according to the particular needs, desires, or particular implementations of the computer 602. For example, the application 607 may be used as one or more components, modules, applications, etc. Additionally, although shown as a single application 607, the application 607 may be implemented as multiple applications 607 on the computer 602. Further, although shown as built into the computer 602, in an alternative implementation, the application 607 may be located external to the computer 602.

[0059] Any number of computers 602 may be associated with or external to the computer system containing the computer 602, where each computer 602 communicates over the network 630. Additionally, the terms “client,” “user,” and other suitable sets of terms may be used interchangeably as appropriate without departing from the scope of this disclosure. Further, this disclosure contemplates that many users may use one computer 602, or one user may use multiple computers 602.

[0060] In some embodiments, computer 602 is implemented as part of a cloud computing system. For example, a cloud computing system can include one or more remote servers and various other cloud components, such as cloud storage units and edge servers. In particular, a cloud computing system can perform one or more computing operations without direct active management by a user device or a local computer system. Thus, a cloud computing system can have different functions distributed across multiple locations from a central server, which can be performed using one or more Internet connections. More specifically, a cloud computing system can operate according to one or more service models, such as Infrastructure as a Service (IaaS), Platform as a Service (PaaS), Software as a Service (SaaS), Mobile "Backend" as a Service (MBaaS), serverless computing, Artificial Intelligence (AI) as a Service (AIaaS), and / or Function as a Service (FaaS).

[0061] Although only a few exemplary embodiments have been described in detail above, those skilled in the art will readily appreciate that many modifications can be made to the exemplary embodiments without materially departing from the invention. Accordingly, all such modifications are intended to be included within the scope of the present disclosure as defined by the appended claims.

Claims

1. A method (300) for water content sensing in an oil-water flow, the method comprising: Obtaining a composite absorption spectrum of the oil-water flow; Obtaining a reference absorption spectrum of a reference fluid; Calculating a slope (400) of data points associated with the composite absorption spectrum of the oil-water flow relative to corresponding data points associated with the reference absorption spectrum of a known fluid; and Determining the water content of the oil-water flow based on the slope (400).

2. The method (300) according to claim 1, wherein, Calculating data points associated with the composite absorption spectrum includes calculating a first derivative (400) of the composite absorption spectrum.

3. The method (300) according to claim 1, wherein, Calculating data points associated with the reference absorption spectrum includes calculating a first derivative (400) of the reference absorption spectrum.

4. The method (300) according to claim 1, wherein The known fluid is water.

5. The method (300) according to claim 1, further comprising, before determining the water content: Recalculating the slope (400) after removing outliers from data points associated with the composite absorption spectrum.

6. The method (300) according to claim 5, wherein, Removing the outliers based on a distance from a linear fitting line having the slope exceeding a certain value.

7. The method (300) according to claim 1, wherein, Obtaining the composite absorption spectrum of the oil-water flow includes performing laser-based absorption spectroscopy.

8. The method (300) according to claim 1, wherein: Calculating the slope is performed for a first region of the composite absorption spectrum, The water content is determined to be higher than 10%, and Based on the water content being higher than 10%, repeating the calculation of the slope for a second region of the composite absorption spectrum.

9. A system (200, 250) for water content sensing in an oil-water flow, the system comprising: A laser-based spectral sensor; And A computer system (602), the computer system (602): Obtaining a composite absorption spectrum of the oil-water flow from the laser-based spectral sensor; Obtaining a reference absorption spectrum of a reference fluid; Calculating a slope (400) of data points associated with the composite absorption spectrum of the oil-water flow relative to corresponding data points associated with the reference absorption spectrum of a known fluid; and Determining the water content of the oil-water flow based on the slope (400).

10. The system (200, 250) according to claim 9, wherein, Calculating data points associated with the composite absorption spectrum includes calculating a first derivative (400) of the composite absorption spectrum.

11. The system (200, 250) according to claim 9, wherein, Calculating data points associated with the reference absorption spectrum includes calculating a first derivative (400) of the reference absorption spectrum.

12. The system (200, 250) according to claim 9, wherein, The known fluid is water.

13. The system (200, 250) according to claim 9, wherein, Before determining the water content, the computer system further: Recalculating the slope (400) after removing outliers from data points associated with the composite absorption spectrum.

14. The system (200, 250) according to claim 13, wherein, Removing the outliers based on a distance from a linear fitting line having the slope exceeding a certain value.

15. The system (200, 250) according to claim 9, wherein: Calculating the slope is performed for a first region of the composite absorption spectrum, The water content is determined to be higher than 10%, and Based on the water content being higher than 10%, repeating the calculation of the slope for a second region of the composite absorption spectrum.

16. A non - transitory computer - readable medium (CRM) (606) stores computer - readable program code for water - content sensing in an oil - water flow. The computer - readable program code causes a computer system (602) to perform the following operations: Obtain a composite absorption spectrum of the oil - water flow; Obtain a reference absorption spectrum of a reference fluid; Calculate a slope (400) of data points associated with the composite absorption spectrum of the oil - water flow relative to corresponding data points associated with the reference absorption spectrum of a known fluid; and Determine the water - content of the oil - water flow based on the slope (400).

17. The non-transitory computer-readable medium (606) according to claim 16, wherein, Calculating data points associated with the composite absorption spectrum includes calculating a first derivative (400) of the composite absorption spectrum.

18. The non-transitory computer-readable medium (606) according to claim 16, wherein, Calculating data points associated with the reference absorption spectrum includes calculating a first derivative (400) of the reference absorption spectrum.

19. The non-transitory computer-readable medium (606) according to claim 16, wherein, The computer - readable program code further causes the computer system to perform the following operations before determining the water - content: Recalculate the slope (400) after removing outliers from data points associated with the composite absorption spectrum.

20. The non - transitory computer - readable medium (606) according to claim 16, wherein: The calculation of the slope is performed for a first region of the composite absorption spectrum, The water - content is determined to be higher than 10%, and Based on the water - content being higher than 10%, the calculation of the slope is repeated for a second region of the composite absorption spectrum.

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