DESALTING SYSTEM AND METHOD FOR HYDROCARBON FLUID PROCESSING

Abstract

A desalting system for processing a hydrocarbon fluid comprising hydrocarbons, water, and dissolved salts includes a separation vessel configured to receive the hydrocarbon fluid and separate it into a liquid hydrocarbon stream and a wastewater stream. The system includes a distillation column with a lower region configured to receive the liquid hydrocarbon stream. A reboiler is in fluid communication with the distillation column, wherein the lower region is positioned vertically below the reboiler such that saline water preferentially accumulates in the lower region and is inhibited from accumulating within the reboiler. Evacuation ports remove accumulated saline water from the lower region. Cleaning ports introduce heated fluid, steam, or chemical descaling agents into the distillation column or reboiler. At least one cleaning mechanism associated with the reboiler includes a removable heating element, mechanical cleaning device, or ultrasonic cleaning device to remove scale or salt deposits.

Description

CROSS-REFERENCE TO RELATED APPLICATIONS

This application claims the benefit of U.S. Provisional Patent Application No. 63/776,418, filed on Mar. 24, 2025, which is incorporated by reference herein in its entirety.

COPYRIGHT STATEMENT

A portion of the disclosure of this patent document contains material that is subject to copyright protection. The copyright owner has no objection to the facsimile reproduction by anyone of the patent document or the patent disclosure as it appears in the Patent and Trademark Office patent file or records, but otherwise reserves all copyright rights whatsoever.

Trademarks used in the disclosure of the invention, and the applicants, make no claim to any trademarks referenced.

BACKGROUND OF THE INVENTION

1) Field of the Invention

The present disclosure relates to systems and methods for processing wellhead fossil fuel fluids, and more particularly to a desalting system and method for removing salts and other contaminants from hydrocarbon fluids using an integrated control system and stabilization system comprising at least a distillation column and reboiler with cleaning mechanisms to minimize scaling and salt deposition.

2) Description of Related Art

Currently the state of the art includes numerous systems targeting the processing wellhead fossil fuel fluids, and more particularly, to removal of contaminants from such fluids however theses system all have processing and output problems. These existing techniques for managing wellhead fluids include mechanical separation, chemical treatment, and gravity-based systems. These methods usually address desalting and fluid processing as distinct steps.

In the oil and gas industry, effective management and processing of wellhead fluids are considerations in optimizing production, minimizing emissions, and addressing operational challenges. Wellhead fluids typically consist of a mixture of hydrocarbons, water, and various impurities, including salts and other minerals. These contaminants can cause issues such as equipment corrosion, scaling, and reduced efficiency of downstream processing units.

Traditional methods for managing wellhead fluids include mechanical separation, chemical treatment, and gravity-based systems. However, these approaches typically address desalting and fluid processing as distinct steps rather than integrating them within a single processing unit. This separation of processes can result in inefficiencies and increased operational expenses. Current desalting solutions, such as chemical demulsifiers or electrostatic separators, are typically employed downstream after initial fluid separation. These approaches may struggle with issues such as inadequate integration, high operational costs, and logistical challenges related to transporting and applying desalting agents effectively.

As oil and gas reservoirs become increasingly depleted and harder to access, the demand for advanced fluid processing techniques continues to grow. The industry is also tasked with reducing production-related emissions, particularly methane. While stabilizer systems offer a potential solution for reducing methane emissions from oil production, frequent fouling and salt accumulation in these systems can hamper their adoption for treating wellhead fluid on-site.

Reboilers and distillation columns used in stabilization systems are susceptible to scaling and salt deposition, which can reduce heat transfer efficiency, restrict fluid flow, and lead to unplanned shutdowns for maintenance. Cleaning and descaling operations for such equipment can be time-consuming and costly, often requiring system shutdown and manual intervention. Various cleaning approaches exist, including chemical treatments, steam cleaning, and mechanical removal of deposits, but each approach presents its own challenges in terms of effectiveness, equipment compatibility, and operational disruption.

The oil and gas industry continues to seek systems and methods that streamline fluid processing, reduce environmental impact, and improve economic performance. There remains an opportunity to enhance the efficiency and cost-effectiveness of wellhead fluid processing through integrated solutions that combine desalting and descaling capabilities with wellhead fluid processing while providing mechanisms for addressing fouling and scale accumulation.

These and other objects, features, and advantages of the present invention will become more readily apparent from the attached drawings and the detailed description of the preferred embodiments, which follow.

SUMMARY OF THE INVENTION

Bearing in mind the problems and deficiencies of the prior art, it is therefore an object of the present invention to provide a desalting system for processing a hydrocarbon fluid comprising hydrocarbons, water, and dissolved salts.

This summary is provided to introduce a selection of concepts in a simplified form that are further described below in the detailed description. This summary is not intended to identify key features or essential features of the claimed subject matter.

According to an aspect of the present disclosure, a desalting system for processing a hydrocarbon fluid comprising hydrocarbons, water, and dissolved salts is provided. The system comprises a separation vessel and a distillation column having a lower region. The system further comprises a reboiler in fluid communication with the distillation column. The lower region of the distillation column is positioned vertically below the reboiler such that saline water preferentially accumulates in the lower region of the distillation column and is inhibited from accumulating within the reboiler. The system also comprises one or more evacuation ports configured to remove accumulated saline water from the lower region of the distillation column. The system comprises one or more cleaning ports configured to introduce heated fluid, steam, or chemical descaling agents into at least one of the distillation column or the reboiler. The system comprises at least one cleaning mechanism associated with the reboiler selected from: (a) a removable heating element configured for extraction from the reboiler to permit mechanical cleaning, (b) a mechanical cleaning device configured to remove scale from internal surfaces of the reboiler, or (c) an ultrasonic cleaning device configured to transmit ultrasonic energy into fluid or surfaces within the reboiler to dislodge salt or scale deposits.

According to other aspects of the present disclosure, the system may include one or more of the following features. The removable heating element may be extractable through a flange opening in the reboiler. The mechanical cleaning device may comprise a scraping, brushing, pigging, or abrasive element configured to contact internal reboiler surfaces. The ultrasonic cleaning device may comprise one or more ultrasonic transducers mounted externally on the reboiler vessel wall. The ultrasonic transducers may be configured to operate while hydrocarbon processing continues. The cleaning ports may be configured to selectively introduce hot oil, steam, acid washing solution, or chemical descaling solution. The system may further comprise a controller configured to initiate one or more cleaning operations in response to detection of salt accumulation.

According to another aspect of the present disclosure, a first embodiment provides a method for desalting a hydrocarbon fluid is provided. The method comprises introducing the hydrocarbon fluid into a separation vessel. The method further comprises directing a hydrocarbon stream to a distillation column. The method also comprises positioning a reboiler in fluid communication with the distillation column such that saline water accumulates in a lower region of the distillation column rather than within the reboiler. The method comprises removing accumulated saline water from the lower region of the distillation column. The method comprises performing at least one in-situ or ex-situ cleaning operation on the reboiler selected from: (i) circulating heated hydrocarbon fluid through the reboiler, (ii) introducing steam or chemical descaling agents into the reboiler, (iii) mechanically cleaning internal surfaces of the reboiler, (iv) removing a heating element from the reboiler for mechanical cleaning or replacement, or (v) applying ultrasonic energy to the reboiler to dislodge salt or scale deposits.

According to other aspects of the present disclosure, the method may include one or more of the following features. Mechanical cleaning may comprise inserting a cleaning tool into the reboiler without fully disassembling the reboiler. Ultrasonic energy may be applied at a frequency that is selected so as to effectively disrupt salt crystal adhesion to internal reboiler surfaces.

According to another aspects of the present disclosure, the system is a process for producing desalted crude oil from wellhead fluid is provided. The process includes using a programmable logic controlled (PLC) stabilization system containing at least a processing column and a reboiler while minimizing scaling, salt depositions and downtime for descaling.

According to other aspects of the present disclosure, the process may include one or more of the following features.

• • a. The process may be used for recovery of the brine for liquid reinjection.
  • b. The fluids being produced from a well may be pressure adjusted, and initially separated into different streams, yielding wastewater, liquid hydrocarbons, and gaseous hydrocarbons.
  • c. The liquid hydrocarbon streams may then be sent to a stabilization system containing at least a distillation column with a reboiler, to output two streams including stabilized crude oil and gaseous hydrocarbons.
  • d. The produced water that remains in the liquid hydrocarbon stream after an initial separation may be further separated from the liquid hydrocarbons in the distillation column, or in the reboiler.
  • e. A chemical mix of desalting and de-emulsion additives may be added in front of the distillation system or into the distillation system.
  • f. Ports may be added to the distillation system to enable hot steam or hot oil cleanup.
  • g. The distillation system may be built to enable the hot crude oil to circulate inside the system.
  • h. A special coating may be used on various components including the heating element of the reboiler, the surface of the reboiler vessel, distillation column, and/or in the pipes to prevent nucleation of salt deposits and/or to enable easy cleanout. The distillation system may be refurbished on a periodic basis to remove salt, scale, and other fouling from the reboiler and the column.
  • i. Sensors in the distillation system may detect accumulation of salty water in the column or the reboiler and through an automated or manual control, cause a valve to open and evacuate the salty water from the column or reboiler.

In some embodiments, some or all the aforementioned desalting steps may be built into the distillation system.

The foregoing general description of the illustrative embodiments and the following detailed description thereof are merely exemplary aspects of the teachings of this disclosure and are not restrictive.

Still other objects and advantages of the invention will in part be obvious and will in part be apparent from the specification.

The above and other objects, which will be apparent to those skilled in the art, are achieved in the present invention which is directed to a desalting system for processing a hydrocarbon fluid comprising hydrocarbons, water, and dissolved salts, the system comprising:

• • a. a separation vessel;
  • b. a distillation column having a lower region;
  • c. a reboiler in fluid communication with the distillation column;
  • d. wherein the lower region of the distillation column is positioned vertically below the reboiler such that saline water preferentially accumulates in the lower region of the distillation column and is inhibited from accumulating within the reboiler;
  • e. one or more evacuation ports configured to remove accumulated saline water from the lower region of the distillation column;
  • f. one or more cleaning ports configured to introduce heated fluid, steam, or chemical descaling agents into at least one of the distillation column or the reboiler;
  • g. and at least one cleaning mechanism associated with the reboiler selected from:
    • i. a removable heating element configured for extraction from the reboiler to permit mechanical cleaning, ii. a mechanical cleaning device configured to remove scale from internal surfaces of the reboiler, or
    • III. an ultrasonic cleaning device configured to transmit ultrasonic energy into fluid or surfaces within the reboiler to dislodge salt or scale deposits.

BRIEF DESCRIPTION OF THE DRAWINGS

A further understanding of the nature and advantages of particular embodiments may be realized by reference to the remaining portions of the specification and the drawings, in which like reference numerals are used to refer to similar components. When reference is made to a reference numeral without specification to an existing sub-label, it is intended to refer to all such multiple similar components.

FIG. 1 illustrates a schematic diagram of an oilfield fluid processing system, according to aspects of the present disclosure.

FIG. 2 illustrates a flowchart of a process for processing oilfield fluids, according to aspects of the present disclosure.

FIG. 3 illustrates a schematic diagram of a programmable logic controller and related components, according to aspects of the present disclosure.

Corresponding reference characters indicate corresponding parts throughout the several views. The exemplifications set out herein illustrate embodiments of the invention and such exemplifications are not to be construed as limiting the scope of the invention in any manner.

DETAILED DESCRIPTION

While various aspects and features of certain embodiments have been summarized above, the following detailed description illustrates a few exemplary embodiments in further detail to enable one skilled in the art to practice such embodiments. The described examples are provided for illustrative purposes and are not intended to limit the scope of the invention.

In the following description, for the purposes of explanation, numerous specific details are set forth in order to provide a thorough understanding of the described embodiments. It will be apparent to one skilled in the art however that other embodiments of the present invention may be practiced without some of these specific details. Several embodiments are described herein, and while various features are ascribed to different embodiments, it should be appreciated that the features described with respect to one embodiment may be incorporated with other embodiments as well. By the same token however, no single feature or features of any described embodiment should be considered essential to every embodiment of the invention, as other embodiments of the invention may omit such features.

In this application the use of the singular includes the plural unless specifically stated otherwise and use of the terms “and” and “or” is equivalent to “and/or,” also referred to as “non-exclusive or” unless otherwise indicated. Moreover, the use of the term “including,” as well as other forms, such as “includes” and “included,” should be considered non-exclusive. Also, terms such as “element” or “component” encompass both elements and components including one unit and elements and components that include more than one unit, unless specifically stated otherwise.

Lastly, the terms “or” and “and/or” as used herein are to be interpreted as inclusive or meaning any one or any combination. Therefore, “A, B or C” or “A, B and/or C” mean “any of the following: A; B; C; A and B; A and C; B and C; A, B and C.” An exception to this definition will occur only when a combination of elements, functions, steps or acts are in some way inherently mutually exclusive.

As this invention is susceptible to embodiments of many different forms, it is intended that the present disclosure be considered as an example of the principles of the invention and not intended to limit the invention to the specific embodiments shown and described.

The terms “header” and “manifold” are used interchangeably herein to mean any arrangement of pipes and/or conduits that serve to convey fluids from one location to another, and could include collections of individual pipes that do not branch.

The term “programmable logic controller” and/or “PLC” as used in the specification is meant to mean any device or collection of devices that can perform operations according to programmed instructions, including computers, microprocessors, configurable controllers, machine control devices, and similar programmable control devices and collections of such devices.

The term refinery injection as used in this disclosure involves introducing chemicals or substances into process streams to prevent corrosion, inhibit deposits, and enhance product quality, typically using specialized pumps and quills. Common applications include corrosion inhibitor injection, wash water injection for desalter operations, and caustic injection to manage pH and chloride levels, protecting equipment and improving reliability.

The term wellhead fluids as used in this disclosure is meant to mean a fluid typically consist of a mixture of hydrocarbons, water, and various impurities, including salts and other minerals. These contaminants can cause significant issues, such as equipment corrosion, scaling, and reduced efficiency of downstream processing units. Traditional methods often involve treating these fluids separately from the wellhead, leading to added complexity and costs.

It should be noted that the oil processing industry has adopted computerized process control and believes it is critical in refineries to maximize operational efficiency, ensure safety, and maintain consistent product quality in real-time. It enables advanced process control (APC) to manage complex,, high-temperature, and high-pressure, operations, reducing energy consumption and minimizing human error while boosting throughput. However, the crude oil and hydrocarbon gas processing systems have not applied computerized process control to address the complexities of crude oil and hydrocarbon gas production.

Key Reasons that advanced process control provided by computerized process control is important for crude oil and hydrocarbon gas production:

• • a. Enhanced Safety and Risk Management: Automated systems constantly monitor for anomalies and take immediate action to prevent accidents, shutdowns, or environmental hazards.
  • b. Optimized Production Efficiency: Artificial Intelligence (AI) and Machine Learning (ML) analyze data to optimize unit operations, such as increasing yield.
  • c. Improved Product Quality: Computerized systems use online analyzers to ensure products are produced that have the highest percentage of stabilized crude oil and hydrocarbon gas production.
  • d. Reduced Operational Costs: By optimizing energy usage and maximizing throughput the crude oil processor can improve their profit margins and reduce waste.
  • e. Stable Operations: Unlike manual controls, automated systems react instantly to process disturbances, maintaining consistent operations despite varying crude oil qualities.

Advanced process control provided by computerized process control systems for real-time management of crude processing allows for proactive, data-driven decisions that replace slower, reactive, and manual, processes.

However the ability to desalt the crude and remove brine and salt bearing liquids has been hampered by the current vision of the process control engineers and operators and by providing a PLC (computerized control system) with the appropriate sensors and control mechanisms results in an efficient process that maximizes stabilized crude oil and gaseous hydrocarbons and the extraction of brine and salt bearing liquids thereby increasing the overall process efficiencies and minimizing down time and unplanned maintenance operations.

Prior to a discussion of the preferred embodiment of the invention, it should be understood that while the features and advantages of the invention are illustrated in terms of a desalting system for processing a hydrocarbon fluid comprising hydrocarbons, water, and dissolved salts.

As disclosed the present invention addresses the deficiencies of traditional methods for managing wellhead fluids, which address desalting and fluid processing as distinct steps rather than integrating them within a single processing unit. This separation of processes can result in inefficiencies and increased operational expenses. Current desalting solutions, such as chemical demulsifiers or electrostatic separators, are typically employed downstream after initial fluid separation. These approaches may struggle with issues such as inadequate integration, high operational costs, and logistical challenges related to transporting and applying desalting agents effectively. The present invention may provide a more effective process to address the desalting proximal to the well head, thereby minimizing the negative effects of the salt.

As oil and gas reservoirs become increasingly depleted and harder to access, the need for advanced fluid processing techniques continues to grow. The industry is also tasked with reducing production-related emissions, particularly methane. While stabilizer systems offer a potential solution for reducing methane emissions from oil production, frequent fouling and salt accumulation in these systems can hamper their adoption for treating wellhead fluid on-site.

The oil and gas industry continues to seek innovative systems and methods that streamline fluid processing, reduce environmental impact, and improve economic performance. The current methods usually address desalting and fluid processing as distinct steps rather than integrating them within a single processing unit. The current separation of processes results in inefficiencies and increased operational expenses. Therefore, there remains an opportunity to enhance the efficiency and cost-effectiveness of wellhead fluid processing through integrated solutions that combine comprehensive desalting and descaling with wellhead fluid processing. An integrated solution that combines comprehensive desalting and descaling with wellhead fluid processing using a crude stabilization system that addresses these needs by enhancing overall phase separation efficiency while minimizing downtime due to fouling and scaling.

One such process improvement is disclosed herein which includes creating a method to extract brine or salt bearing liquids and managing the process by providing real time control to the process so as to maximize the extraction of the brine or salt bearing liquids and maximize the production of the stabilized crude oil and gaseous hydrocarbons while minimizing the problems with unscheduled maintenance or down time to the equipment.

The following description sets forth examples of aspects of the present disclosure. It should be recognized, however, that such description is not intended as a limitation on the scope of the present disclosure. Rather, the description also encompasses combinations and modifications to those examples described herein.

The present disclosure relates to systems and processes for producing desalted crude oil from wellhead fluid using an integrated process and control system that uses computerized management of the process provided by using a programmable logic controlled (PLC) stabilization system that provides real-time control over the process to maximize the desalting process and reduce cost to the processor.

The stabilization system may include at least a stabilization column and a reboiler, and may be designed to minimize scaling, salt depositions, and downtime for descaling.

In one embodiment, the process is used for recovery of the brine for liquid reinjection.

In some cases, the process may involve initially separating wellhead fluid into different streams, including wastewater, liquid hydrocarbons, and gaseous hydrocarbons. The liquid hydrocarbon streams may then be directed to the stabilization system for further processing. The stabilization system may output two product streams: stabilized crude oil and gaseous hydrocarbons.

The disclosed systems and processes may incorporate various features to enhance desalting and descaling efficiency. These features may include chemical injection of desalting and de-emulsion additives, ports for hot steam or hot oil cleanup, circulation of hot crude oil within the system, and special coatings on various components to prevent salt deposits or facilitate easy cleanout.

In some cases, the stabilization system may include sensors to detect accumulation of salty water, salts, scale, or other fouling. The programmable logic controller (PLC) may use data from these sensors to automate various processes, such as evacuating salty water, triggering hot oil recycling, or recommending external cleanout procedures via some form of operator interface. Sensors may be responsive to process parameters at a particular location within the system such as pressure, temperature, liquid level, level of interface between two liquids of differing density, flow rate, chemical composition, etc. Devices controlled under the direction of the PLC may include valves and/or pumps that control flow into, between, and from various components of the system and devices such as heating elements that control process parameters within a component.

The disclosed invention may offer several advantages over traditional wellhead fluid processing methods. By integrating comprehensive desalting and descaling processes directly within the wellhead fluid processing system, the invention may optimize fluid treatment, reduce operational costs, and extend the lifespan of processing equipment while minimizing emissions.

The following description sets forth exemplary aspects of the present disclosure. It should be recognized, however, that such description is not intended as a limitation on the scope of the present disclosure. Rather, the description also encompasses combinations and modifications to those exemplary aspects described herein.

Referring to FIG. 1, a first embodiment discloses a desalting system for processing hydrocarbon fluids is illustrated. The hydrocarbon fluids contain hydrocarbons, water, and dissolved salts, and originate from an oil well 100. The desalting system produces desalted crude oil from wellhead fluid while minimizing scaling, salt deposition, and downtime for descaling. The desalting system integrates desalting and descaling capabilities within a stabilization system comprising a separator 101, a distillation column 102, and a reboiler 103 with cleaning mechanisms.

With continued reference to FIG. 1, the separator 101 performs an initial separation of the wellhead fluid into different streams, which include wastewater, liquid hydrocarbons, and gaseous hydrocarbons. The separator 101 includes an interface level sensor 101a for monitoring the oil-water interface level. The separator 101 also includes a weir 101b, illustrated as a vertical dashed line, over which lighter liquid hydrocarbons flow while denser wastewater collects behind the weir 101b. The separator 101 uses an electric charge to increase water separation from the oil. The separator 101 uses a coalescing media to increase water separation from the oil. The separator 101 is back pressure controlled. The separator 101 is a horizontal separator instead of a vertical one for handling fluids with high gas-to-liquid ratios or for installations with height restrictions. The system includes a pre-flash drum before the separator 101 to remove the lightest components of the wellhead fluid. The system employs centrifugal separators or hydrocyclones to enhance the separation of water and oil. The system includes electrostatic coalescers to promote coalescence of water droplets and facilitate their separation from the oil.

A liquid hydrocarbon stream 110 exits the separator 101 and is directed to the distillation column 102. The distillation column 102 includes an interface level sensor 102a for monitoring water buildup and a weir 102b. The distillation column 102 is randomly packed with materials such as ceramic rings, metal saddles, or structured packing. The distillation column 102 is equipped with trays such as bubble cap trays, sieve trays, or valve trays. A special coating is used on the distillation column 102 to prevent nucleation of salt deposits or enable easy cleanout. The special coating has a smooth, non-porous surface that reduces the likelihood of salt crystals nucleating and growing on the coated surfaces. The special coating has low surface energy to discourage adhesion of salt deposits. The special coating has non-stick properties that allow salt deposits or other fouling materials to be more easily removed during cleaning processes.

The reboiler 103 is in fluid communication with the distillation column 102 and includes an interface level sensor 103a for monitoring water buildup and a weir 103b. The reboiler 103 includes a heating element 116 for providing heat to facilitate the separation process by vaporizing more volatile components. The reboiler 103 is equipped with a flange that enables the extraction of the heating element 116 for thorough cleaning or replacement. The reboiler 103 uses a kettle-type design instead of a traditional shell-and-tube design for improved fouling resistance and ease of maintenance. The reboiler 103 uses direct-fired heaters instead of steam heating. The reboiler 103 uses electric heating elements instead of steam heating. A special coating is used on the heating element 116 of the reboiler 103, the surface of the reboiler 103 vessel, and pipes to prevent nucleation of salt deposits or enable easy cleanout.

As further shown in FIG. 1, a stabilized crude oil 115 leaves the reboiler 103 to a product manifold for distribution. A desalted crude flow/pressure control 118 manages the output of the stabilized crude oil 115. The stabilized desalted crude is cooled before the product manifold using a heat exchanger. The stabilized desalted crude is cooled using air coolers instead of or in addition to liquid-based heat exchangers.

A residue gas header 114 collects gaseous hydrocarbons from the separator 101 and the distillation column 102. The residue gas is used on-site for fuel. The residue gas is evacuated to a midstream pipeline. The residue gas is used for gas lift reinjection. The residue gas is treated in a gas sweetening unit to remove hydrogen sulfide and other contaminants. The residue gas is directed to a flare system as a safety measure for handling excess gas. The residue gas is used for on-site power generation using gas-fired generators or turbines. The system includes gas composition analyzers to monitor gas quality of the residue gas. The system includes flow meters to measure gas volumes of the residue gas. The system includes automated valves to control the routing of residue gas to different utilization options.

A cleaning header 108 enables steam or hot oil cleanup of the separator 101, the distillation column 102, and the reboiler 103. The cleaning header 108 is used to introduce acid washing solutions for removing certain types of scale or mineral deposits. A chemical injection pump 106 and an injection header 109 introduce desalting and de-emulsification chemicals into the process. The chemical injection system includes multiple injection points for different types of chemicals for more precise control over desalting and de-emulsification processes. The chemical injection system incorporates inline mixing devices to ensure thorough blending of the chemicals with the wellhead fluid.

A water treatment unit 111 processes produced water. A wastewater stream 112 removes produced water from the separator 101 for disposal. A reduced-salt water stream 113 exits the water treatment unit 111 after treatment. A wastewater/water recycle flow/pressure control 119 manages the water routing. The water treatment unit 111 uses filtration to reduce total dissolved solids in the produced water. The water treatment unit 111 uses reverse osmosis to reduce total dissolved solids in the produced water. The water treatment unit 111 uses chemical treatment to remove dissolved minerals and other impurities from the water. The water treatment unit 111 uses membrane filtration to further reduce total dissolved solids in the produced water. The water treatment unit 111 uses electrocoagulation to further reduce total dissolved solids in the produced water. The treated water with reduced total dissolved solids is reinjected into the separator 101 as wash water. The wastewater is reinjected into the reservoir for stimulation purposes. The wastewater is injected into a Class II disposal well. The wastewater is transported off-site via trucks for treatment or disposal at specialized facilities. The system includes sensors to monitor water quality parameters of the wastewater. The system includes flow meters to measure water volumes of the wastewater. The system includes automated valves and pumps to control the routing of water within the system.

With continued reference to FIG. 1, a pressure regulating valve 107 regulates the system inlet flow. A reboiler water/oil evacuation pump 104 evacuates water and oil from the reboiler 103. A separator water evacuation pump 105 evacuates water from the separator 101. A distillation column water evacuation pump 117 evacuates water from the distillation column 102. A reboiler water evacuation valve 121 controls water evacuation from the reboiler 103. A valve 120 controls flow within the system. Flow between various components is controlled by valves alone using gravity and pressure to motivate the flow instead of pumps.

The distillation system is refurbished on a periodic basis to remove salt, scale, and other fouling from the reboiler 103 and the distillation column 102. The refurbishment process uses chemical cleaning to address fouling. The refurbishment process uses high-pressure washing to address fouling. The refurbishment process uses mechanical scrubbing to address fouling. The system incorporates online analyzers to continuously monitor the salt content of the crude oil at various stages of the process. The system includes a salt recovery unit to process the concentrated brine and recover valuable minerals as a byproduct. The system includes heat integration between hot and cold streams to reduce external energy requirements for heating and cooling.

Referring to FIG. 3, a programmable logic controller 200 monitors and controls the desalting system. The programmable logic controller 200 is in electrical signal communication with the interface level sensor 101a, the interface level sensor 102a, and the interface level sensor 103a. The programmable logic controller 200 communicates with and controls the reboiler water/oil evacuation pump 104, the separator water evacuation pump 105, the chemical injection pump 106, the pressure regulating valve 107, the cleaning header 108, the heating element 116, the distillation column water evacuation pump 117, the desalted crude flow/pressure control 118, the wastewater/water recycle flow/pressure control 119, and the reboiler water evacuation valve 121. Communication between the programmable logic controller 200 and sensors or controlled devices is wired. Communication between the programmable logic controller 200 and sensors or controlled devices is wireless.

The programmable logic controller 200 detects accumulation of salts, scale or other fouling in the system and triggers recycling of hot oil in the system. The programmable logic controller 200 detects that the distillation system efficiency has gone down and issues a message to the operator recommending external hot oil wash. The programmable logic controller 200 sends notification to the operator that external hot oil wash is recommended based on a configurable timer 204. The programmable logic controller 200 sends notification to the operator that a comprehensive refurbish is recommended based on the configurable timer 204 or if performance degrades below a certain configurable threshold. The programmable logic controller 200 uses machine learning to aid in determining when sensor input indicates that a condition exists where remedial action is to be taken. The programmable logic controller 200 detects increased pressure drop across the distillation column 102 as indicative of blockage caused by salt accumulation and scaling. The programmable logic controller 200 monitors power consumption of the heating element 116 and temperature in the reboiler 103 to determine that power requirement has increased indicating salt and scale accumulation on the heating element 116. Chemical sensors monitor the composition of the outgoing stabilized hydrocarbon stream to allow the programmable logic controller 200 to detect a salt content over a specified threshold. An operator interface 202 presents information to an operator and allows the operator to provide input to the programmable logic controller 200. The operator interface 202 is provided at least in part by appropriate software running on a mobile computing device used by the operator.

Referring to FIG. 2, a process 300 for processing oilfield fluids to produce desalted crude oil is illustrated. The process 300 integrates separation, stabilization, chemical treatment, and automated monitoring and cleaning operations coordinated to produce desalted crude oil while minimizing scaling, salt depositions, and downtime for descaling.

FIG. 1 is a schematic diagram of an oilfield fluid processing system for processing wellhead fluid from the oil well 100. The oilfield fluid processing system includes the separator 101, the distillation column 102, and the reboiler 103, each connected via pipelines. The pipelines are connected by flanges, shown as parallel lines forming a break in FIG. 1. The programmable logic controller 200 is indicated in the top right corner of FIG. 1 and controls the operation of the oilfield fluid processing system. The oilfield fluid processing system processes wellhead fluid to produce the stabilized crude oil 115 and gaseous hydrocarbons collected via the residue gas header 114.

With continued reference to FIG. 1, the separator 101 receives wellhead fluid from the oil well 100 after the wellhead fluid passes through the pressure regulating valve 107. The separator 101 performs an initial separation of the wellhead fluid into wastewater, liquid hydrocarbons, and gaseous hydrocarbons. The separator 101 uses an electric charge to increase water separation from the oil. The separator 101 uses a coalescing media to increase water separation from the oil. The separator 101 is back pressure controlled. The separator 101 is a horizontal separator for handling fluids with high gas-to-liquid ratios or for installations with height restrictions. The system includes a pre-flash drum before the separator 101 to remove the lightest components of the wellhead fluid. The system employs centrifugal separators or hydrocyclones to enhance the separation of water and oil. The system includes electrostatic coalescers to promote coalescence of water droplets and facilitate their separation from the oil.

The liquid hydrocarbon stream 110 exits the separator 101 and is directed to the distillation column 102. The distillation column 102 is randomly packed with materials such as ceramic rings, metal saddles, or structured packing. The distillation column 102 is equipped with trays such as bubble cap trays, sieve trays, or valve trays. A special coating is used on the distillation column 102 to prevent nucleation of salt deposits or enable easy cleanout. The special coating has a smooth, non-porous surface that reduces the likelihood of salt crystals nucleating and growing on the coated surfaces. The special coating has low surface energy to discourage adhesion of salt deposits. The special coating has non-stick properties that allow salt deposits or other fouling materials to be more easily removed during cleaning processes. A distillation column water evacuation valve 122 controls water evacuation from the distillation column 102.

As further shown in FIG. 1, the reboiler 103 is in fluid communication with the distillation column 102. The reboiler 103 includes the heating element 116 for providing heat to facilitate the separation process by vaporizing more volatile components. A special coating is used on the heating element 116 of the reboiler 103, the surface of the reboiler 103 vessel, and pipes to prevent nucleation of salt deposits or enable easy cleanout. The reboiler 103 is equipped with a flange that enables the extraction of the heating element 116 for thorough cleaning or replacement. The reboiler 103 uses a kettle-type design instead of a traditional shell-and-tube design for improved fouling resistance and ease of maintenance. The reboiler 103 uses direct-fired heaters instead of steam heating. The reboiler 103 uses electric heating elements instead of steam heating.

The stabilized crude oil 115 leaves the reboiler 103 to a product manifold for distribution. The desalted crude flow/pressure control 118 manages the output of the stabilized crude oil 115. The stabilized desalted crude is cooled before the product manifold using a heat exchanger. The stabilized desalted crude is cooled using air coolers instead of or in addition to liquid-based heat exchangers.

With continued reference to FIG. 1, the residue gas header 114 collects gaseous hydrocarbons from the separator 101 and the distillation column 102. The residue gas is used on-site for fuel. The residue gas is evacuated to a midstream pipeline. The residue gas is used for gas lift reinjection. The residue gas is treated in a gas sweetening unit to remove hydrogen sulfide and other contaminants. The residue gas is directed to a flare system as a safety measure for handling excess gas. A valve 123 controls flow of residue gas within the system. A valve 124 controls flow within the system.

The chemical injection pump 106 and the injection header 109 introduce desalting and de-emulsification chemicals into the process. The chemical injection system includes multiple injection points for different types of chemicals for more precise control over desalting and de-emulsification processes. The chemical injection system incorporates inline mixing devices to ensure thorough blending of the chemicals with the wellhead fluid.

The water treatment unit 111 processes produced water. The water treatment unit 111 uses filtration to reduce total dissolved solids in the produced water. The water treatment unit 111 uses reverse osmosis to reduce total dissolved solids in the produced water. The water treatment unit 111 uses chemical treatment to remove dissolved minerals and other impurities from the water. The water treatment unit 111 uses membrane filtration to further reduce total dissolved solids in the produced water. The water treatment unit 111 uses electrocoagulation to further reduce total dissolved solids in the produced water. The treated water with reduced total dissolved solids is reinjected into the separator 101 as wash water. The wastewater is reinjected into the reservoir for stimulation purposes. The wastewater is injected into a Class II disposal well. The wastewater is transported off-site via trucks for treatment or disposal at specialized facilities.

The system incorporates online analyzers to continuously monitor the salt content of the crude oil at various stages of the process. The system includes a salt recovery unit to process the concentrated brine and recover valuable minerals as a byproduct. The system includes heat integration between hot and cold streams to reduce external energy requirements for heating and cooling.

The programmable logic controller 200 controls the oilfield fluid processing system. The programmable logic controller 200 detects accumulation of salts, scale or other fouling in the system and triggers recycling of hot oil in the system. The programmable logic controller 200 detects that the distillation system efficiency has gone down and issues a message to the operator recommending external hot oil wash. The programmable logic controller 200 monitors power consumption of the heating element 116 and temperature in the reboiler 103 to determine that power requirement has increased indicating salt and scale accumulation on the heating element 116. Chemical sensors monitor the composition of the outgoing stabilized hydrocarbon stream to allow the programmable logic controller 200 to detect a salt content over a specified threshold. Communication between the programmable logic controller 200 and sensors or controlled devices is wired. Communication between the programmable logic controller 200 and sensors or controlled devices is wireless. The operator interface 202 is provided at least in part by appropriate software running on a mobile computing device used by the operator.

With continued reference to FIG. 1, the separator 101 receives wellhead fluid from the oil well 100 after the wellhead fluid passes through the pressure regulating valve 107. The pressure regulating valve 107 regulates the system inlet flow by performing pressure reduction on the wellhead fluid. The pressure reduction step prepares the wellhead fluid for subsequent processing stages within the desalting system.

The separator 101 performs an initial separation of the wellhead fluid into different streams including wastewater, liquid hydrocarbons, and gaseous hydrocarbons. The interface level sensor 101a monitors the oil-water interface level within the separator 101. The weir 101b allows discrete hydrocarbon streams to spill over while denser wastewater collects behind the weir 101b. The liquid hydrocarbon stream 110 exits the separator 101 by spilling over the weir 101b and is directed to the distillation column 102 for further processing.

The separator water evacuation pump 105 removes produced water from the separator 101. The produced water exits the separator 101 as the wastewater stream 112 for disposal or further treatment by the water treatment unit 111. The wastewater/water recycle flow/pressure control 119 manages the routing of water removed from the separator 101.

As further shown in FIG. 1, the separator 101 uses an electric charge to increase water separation from the oil. An electric field is applied across the separator 101, which causes water droplets to coalesce more rapidly. The electrostatic coalescence process is effective for breaking down stable emulsions and separating fine water droplets that remain dispersed in the oil phase.

The separator 101 uses a coalescing media to increase water separation from the oil. The coalescing media provides a large surface area for small water droplets to combine and form larger droplets, which are easier to separate from the oil phase. The coalescing process enhances the overall efficiency of the water-oil separation in the separator 101.

The separator 101 is back pressure controlled to maintain appropriate operating conditions during the separation process. The separator 101 is a horizontal separator instead of a vertical one for handling fluids with high gas-to-liquid ratios or for installations with height restrictions.

With continued reference to FIG. 1, the system includes a pre-flash drum before the separator 101 to remove the lightest components of the wellhead fluid. The pre-flash drum reduces the load on the separator 101 and the distillation column 102, improving overall system efficiency.

The system employs centrifugal separators or hydrocyclones to enhance the separation of water and oil. The centrifugal separators or hydrocyclones use centrifugal force to separate fluids of different densities, improving the efficiency of the desalting process.

The system includes electrostatic coalescers to promote coalescence of water droplets and facilitate their separation from the oil. The electrostatic coalescers apply an electric field to the fluid, promoting the coalescence of water droplets for more efficient separation from the oil phase.

With continued reference to FIG. 1, the chemical injection pump 106 and the injection header 109 introduce desalting and de-emulsification chemicals into the process. The chemical injection pump 106 delivers chemicals through the injection header 109 at controlled rates to enhance the separation of water and impurities from the oil. The desalting and de-emulsification chemicals break down emulsions and facilitate the separation of water and oil within the desalting system.

The chemicals are added to the wellhead fluid before the wellhead fluid enters the separator 101. The chemicals are added at various points within the desalting system, such as the distillation column 102 and the reboiler 103. The injection of the desalting and de-emulsification chemicals at multiple locations within the desalting system enhances the overall efficiency of water-oil separation throughout the process.

As further shown in FIG. 1, the chemical injection system includes multiple injection points for different types of chemicals. The multiple injection points allow for more precise control over the desalting and de-emulsification processes by enabling different chemicals to be introduced at locations where the different chemicals are most effective. The chemical injection system incorporates inline mixing devices to ensure thorough blending of the chemicals with the wellhead fluid. The inline mixing devices promote uniform distribution of the chemicals throughout the wellhead fluid, improving the effectiveness of the desalting and de-emulsification processes.

With continued reference to FIG. 1, the liquid hydrocarbon stream 110 exits the separator 101 and is fed to the distillation column 102. The distillation column 102 further separates the hydrocarbons based on boiling points. The distillation column 102 receives the liquid hydrocarbon stream 110 containing hydrocarbons and residual water with dissolved salts that were not removed during the initial separation in the separator 101.

The distillation column 102 includes the interface level sensor 102a for monitoring water buildup within the distillation column 102. The interface level sensor 102a detects the accumulation of saline water in the distillation column 102 and provides data to the programmable logic controller 200 for automated control of water evacuation processes. The weir 102b within the distillation column 102 allows lighter liquid hydrocarbons to flow over while denser saline water collects behind the weir 102b in a lower region of the distillation column 102.

As further shown in FIG. 1, the distillation column water evacuation pump 117 and the distillation column water evacuation valve 122 evacuate accumulated saline water from the lower region of the distillation column 102. The distillation column water evacuation valve 122 opens to allow the distillation column water evacuation pump 117 to remove the accumulated saline water from the distillation column 102. The programmable logic controller 200 controls the distillation column water evacuation pump 117 and the distillation column water evacuation valve 122 based on data from the interface level sensor 102a to maintain appropriate operating conditions within the distillation column 102.

The distillation column 102 is randomly packed with materials such as ceramic rings, metal saddles, or structured packing. The random packing materials provide a large surface area for vapor-liquid contact, improving the separation of components in the hydrocarbon stream based on boiling points. The distillation column 102 is equipped with trays such as bubble cap trays, sieve trays, or valve trays. Each tray type offers specific advantages in terms of efficiency, pressure drop, or fouling resistance, allowing the distillation column 102 to be tailored to the particular characteristics of the wellhead fluid being processed.

With continued reference to FIG. 1, the reboiler 103 is in fluid communication with the distillation column 102 and is positioned such that the lower region of the distillation column 102 is vertically below the reboiler 103. This vertical positioning causes saline water to preferentially accumulate in the lower region of the distillation column 102 rather than within the reboiler 103. The denser saline water gravitates toward the lower region of the distillation column 102 due to the density difference between the saline water and the lighter hydrocarbon liquids. The saline water is inhibited from accumulating within the reboiler 103 because the reboiler 103 receives hydrocarbon liquids that have already passed over the weir 102b in the distillation column 102, leaving the denser saline water behind in the lower region of the distillation column 102.

The heating element 116 within the reboiler 103 provides heat to facilitate the separation process by vaporizing more volatile components of the hydrocarbon liquids. The heating element 116 transfers thermal energy to the hydrocarbon liquids within the reboiler 103, causing lighter hydrocarbon fractions to vaporize. The vaporized hydrocarbons return to the distillation column 102 to enhance the separation of components based on boiling points. The heating element 116 operates at temperatures sufficient to drive off volatile components while maintaining the heavier hydrocarbon fractions in liquid form for output as the stabilized crude oil 115.

As further shown in FIG. 1, the interface level sensor 103a monitors water buildup within the reboiler 103. The interface level sensor 103a detects any accumulation of water that enters the reboiler 103 despite the vertical positioning that causes saline water to preferentially accumulate in the distillation column 102. The interface level sensor 103a provides data to the programmable logic controller 200 for monitoring and control of water levels within the reboiler 103.

The weir 103b within the reboiler 103 allows lighter liquid hydrocarbons to flow over while any denser water that enters the reboiler 103 collects behind the weir 103b. The weir 103b provides a physical barrier that separates the water phase from the hydrocarbon phase within the reboiler 103, enabling removal of any accumulated water without disrupting the flow of stabilized crude oil from the reboiler 103.

The reboiler water/oil evacuation pump 104 and the reboiler water evacuation valve 121 remove accumulated water and oil from the reboiler 103. The reboiler water evacuation valve 121 opens to allow the reboiler water/oil evacuation pump 104 to evacuate water that collects behind the weir 103b. The programmable logic controller 200 controls the reboiler water/oil evacuation pump 104 and the reboiler water evacuation valve 121 based on data from the interface level sensor 103a to maintain appropriate operating conditions within the reboiler 103 and prevent water accumulation from interfering with the heating and separation processes.

With continued reference to FIG. 1, the reboiler 103 is equipped with a flange that enables the extraction of the heating element 116 for thorough cleaning or replacement. The flange provides access to the heating element 116 without requiring disassembly of the entire reboiler 103 vessel. Maintenance personnel remove the heating element 116 through the flange opening to address fouling issues that accumulate on the heating surfaces over time, including salt deposits and scale buildup.

The reboiler 103 uses a kettle-type design instead of a traditional shell-and-tube design for improved fouling resistance and ease of maintenance. The kettle-type design provides advantages when processing wellhead fluids with high scaling potential by allowing easier access to internal surfaces for cleaning and inspection.

The reboiler 103 uses direct-fired heaters instead of steam heating. The direct-fired heaters provide heat directly to the hydrocarbon liquids within the reboiler 103 without requiring a separate steam generation system. The reboiler 103 uses electric heating elements instead of steam heating. The electric heating elements offer advantages in terms of control precision and are suitable for locations where steam generation is not practical.

With continued reference to FIG. 1, the cleaning header 108 enables steam, hot oil, or chemical descaling agent cleanup of the separator 101, the distillation column 102, and the reboiler 103. The cleaning header 108 is configured to introduce heated fluid into the separator 101, the distillation column 102, and the reboiler 103 to remove salt deposits, scale, and other fouling materials from internal surfaces. The cleaning header 108 connects to ports on the separator 101, the distillation column 102, and the reboiler 103 that allow introduction of cleaning agents during maintenance operations.

The cleaning header 108 introduces steam into the separator 101, the distillation column 102, and the reboiler 103 for steam cleaning operations. Steam cleaning removes certain types of deposits from internal surfaces and maintains system temperatures during the cleaning process. The steam flows through the cleaning header 108 and enters the separator 101, the distillation column 102, and the reboiler 103 through dedicated cleaning ports configured to distribute the steam across internal surfaces where salt and scale accumulate.

As further shown in FIG. 1, the cleaning header 108 introduces hot oil from an external source into the separator 101, the distillation column 102, and the reboiler 103 for intensive cleaning operations. The hot oil circulates through the separator 101, the distillation column 102, and the reboiler 103 to dissolve and remove salt deposits and other fouling materials. The circulation of heated hydrocarbon fluid through the reboiler 103 maintains elevated temperatures that prevent solidification of deposits and facilitate removal of accumulated materials from internal surfaces including the heating element 116.

The cleaning header 108 introduces acid washing solutions into the separator 101, the distillation column 102, and the reboiler 103 for removing certain types of scale or mineral deposits. The acid washing solutions react with mineral scale deposits to dissolve and remove the scale from internal surfaces of the separator 101, the distillation column 102, and the reboiler 103. The cleaning header 108 introduces chemical descaling agents into the separator 101, the distillation column 102, and the reboiler 103 to address fouling that cannot be removed through steam or hot oil cleaning alone.

With continued reference to FIG. 1, the desalting system includes mechanical cleaning of internal surfaces of the reboiler 103 to remove scale and salt deposits. A mechanical cleaning device contacts internal reboiler surfaces to scrape, brush, or abrade accumulated deposits from the surfaces. The mechanical cleaning device comprises a scraping element, a brushing element, a pigging element, or an abrasive element configured to contact internal surfaces of the reboiler 103 and physically remove adhered salt and scale deposits.

The heating element 116 is removed from the reboiler 103 through the flange opening for mechanical cleaning or replacement. Maintenance personnel extract the heating element 116 from the reboiler 103 and perform mechanical cleaning on the heating element 116 to remove salt and scale deposits that accumulate on heating surfaces. The removal of the heating element 116 for cleaning or replacement addresses fouling on the heating element 116 without requiring full disassembly of the reboiler 103.

As further shown in FIG. 1, an ultrasonic cleaning device applies ultrasonic energy to the reboiler 103 to dislodge salt or scale deposits from internal surfaces. The ultrasonic cleaning device comprises one or more ultrasonic transducers mounted externally on the reboiler 103 vessel wall. The ultrasonic transducers transmit ultrasonic energy into fluid or surfaces within the reboiler 103 at a frequency effective to disrupt salt crystal adhesion to internal reboiler surfaces. The ultrasonic transducers operate while hydrocarbon processing continues, allowing cleaning operations to occur without interrupting production.

The distillation system is refurbished on a periodic basis to remove salt, scale, and other fouling from the reboiler 103 and the distillation column 102. The refurbishment process uses chemical cleaning to address fouling by introducing chemical cleaning agents through the cleaning header 108 to dissolve and remove accumulated deposits. The refurbishment process uses high-pressure washing to address fouling by directing high-pressure fluid streams against internal surfaces of the reboiler 103 and the distillation column 102 to dislodge adhered deposits. The refurbishment process uses mechanical scrubbing to address fouling by physically contacting internal surfaces with scrubbing elements to remove deposits that resist chemical or high-pressure cleaning methods.

With continued reference to FIG. 1, the desalting system incorporates anti-fouling coatings on various components to prevent nucleation of salt deposits and enable easy cleanout during maintenance operations. A special coating is applied to the heating element of the reboiler, the surface of the reboiler vessel, the distillation column, and associated piping throughout the desalting system. The special coating provides a barrier between the component surfaces and the hydrocarbon fluids containing dissolved salts, reducing the tendency for salt crystals to form and adhere to the coated surfaces.

The special coating has a smooth, non-porous surface that reduces the likelihood of salt crystals nucleating and growing on the coated surfaces. The smooth surface eliminates microscopic irregularities and crevices where salt crystals would otherwise initiate formation. The non-porous characteristic of the coating prevents penetration of saline fluids into the coating material, maintaining the integrity of the protective barrier over extended operating periods. The smooth, non-porous surface provides fewer sites for initial crystal formation, thereby inhibiting the growth of salt deposits that would otherwise accumulate on uncoated surfaces.

As further shown in FIG. 1, the special coating has low surface energy to discourage adhesion of salt deposits. The low surface energy characteristic reduces the attractive forces between the coated surface and salt particles or crystals that contact the surface. Salt deposits that form in the fluid phase exhibit reduced tendency to bond with the low surface energy coating, allowing such deposits to remain suspended in the fluid or to be carried away by fluid flow rather than adhering to component surfaces. The low surface energy property of the coating maintains effectiveness even when salt crystals contact the coated surfaces, as the reduced adhesion forces prevent strong bonding between the deposits and the coating.

The special coating has non-stick properties that allow salt deposits or other fouling materials to be more easily removed during cleaning processes. The non-stick characteristics enable accumulated deposits to release from the coated surfaces when subjected to cleaning operations such as hot oil circulation, steam cleaning, or chemical descaling. Fouling materials that accumulate on the non-stick coating surfaces exhibit weaker adhesion compared to fouling on uncoated surfaces, reducing the time and effort required for cleaning operations. The non-stick properties of the coating facilitate removal of deposits through the cleaning header without requiring mechanical scrubbing or aggressive chemical treatments that could damage component surfaces.

With continued reference to FIG. 1, the desalted crude flow/pressure control 118 manages the output of the stabilized crude oil 115 from the reboiler 103. The desalted crude flow/pressure control 118 regulates the flow rate and pressure of the stabilized crude oil 115 as the stabilized crude oil 115 exits the reboiler 103 and travels toward a product manifold for distribution. The desalted crude flow/pressure control 118 maintains appropriate flow conditions to ensure consistent delivery of the stabilized crude oil 115 from the desalting system. The desalted crude flow/pressure control 118 receives control signals from the programmable logic controller 200 to adjust flow and pressure parameters based on system operating conditions and production requirements.

As further shown in FIG. 1, the valve 120 controls flow within the desalting system. The valve 120 opens and closes to regulate fluid movement between components of the desalting system based on operating requirements. The valve 123 controls flow of residue gas within the desalting system. The valve 123 regulates the routing of gaseous hydrocarbons collected by the residue gas header 114 to downstream utilization options including pipeline injection, on-site power generation, or gas lift operations. The valve 124 controls flow within the desalting system. The valve 124 operates in coordination with other valves and pumps throughout the desalting system to maintain appropriate fluid routing and pressure conditions during normal operations and cleaning cycles.

With continued reference to FIG. 1, the stabilized desalted crude is cooled before the product manifold using a heat exchanger. The heat exchanger transfers thermal energy from the hot stabilized crude oil 115 exiting the reboiler 103 to a cooling medium. The cooling step reduces the vapor pressure of the stabilized crude oil 115, making the stabilized crude oil 115 safer for storage and transportation. The cooling process prevents the loss of lighter hydrocarbons that would otherwise vaporize at higher temperatures during storage and handling operations.

The stabilized desalted crude is cooled using air coolers instead of or in addition to liquid-based heat exchangers. Air coolers transfer thermal energy from the hot stabilized crude oil 115 to ambient air through finned tube surfaces. Air cooling provides advantages in locations where water for cooling is scarce or expensive. The air coolers operate by forcing ambient air across heat transfer surfaces carrying the hot stabilized crude oil 115, reducing the temperature of the stabilized crude oil 115 to levels suitable for storage and transportation without requiring water-based cooling systems.

With continued reference to FIG. 1, the water treatment unit 111 processes produced water removed from the separator 101, the distillation column 102, and the reboiler 103 to reduce total dissolved solids content. The water treatment unit 111 receives produced water containing dissolved salts and other impurities that were separated from the hydrocarbon fluids during processing operations. The water treatment unit 111 outputs treated water with reduced concentrations of dissolved solids suitable for reuse within the desalting system or for disposal through various methods.

The water treatment unit 111 uses filtration to reduce total dissolved solids in the produced water. Filtration removes suspended particles and certain dissolved constituents from the produced water by passing the water through filter media that capture contaminants. The water treatment unit 111 uses reverse osmosis to reduce total dissolved solids in the produced water. Reverse osmosis forces the produced water through semi-permeable membranes that reject dissolved salts and other ionic species, producing a permeate stream with reduced salt content.

As further shown in FIG. 1, the water treatment unit 111 uses chemical treatment to remove dissolved minerals and other impurities from the water. Chemical treatment introduces reagents that react with dissolved constituents to precipitate or neutralize contaminants for subsequent removal. The water treatment unit 111 uses membrane filtration to further reduce total dissolved solids in the produced water. Membrane filtration employs porous membrane barriers that separate dissolved and suspended materials based on molecular size and charge characteristics.

The water treatment unit 111 uses electrocoagulation to further reduce total dissolved solids in the produced water. Electrocoagulation applies electrical current to the produced water through sacrificial electrodes, generating metal ions that destabilize dissolved and colloidal contaminants for aggregation and removal. The electrocoagulation process addresses contaminants that resist removal through conventional filtration or chemical treatment methods.

With continued reference to FIG. 1, the wastewater stream 112 exits the separator 101 and carries produced water for disposal or treatment. The wastewater stream 112 contains water separated from the wellhead fluid during initial processing in the separator 101, including dissolved salts and other impurities present in the original wellhead fluid. The wastewater stream 112 is directed to the water treatment unit 111 for processing or is routed directly to disposal depending on water quality and regulatory requirements.

The reduced-salt water stream 113 exits the water treatment unit 111 after treatment operations reduce the total dissolved solids content of the produced water. The reduced-salt water stream 113 contains treated water suitable for reuse within the desalting system or for disposal through methods that require lower salt concentrations than the untreated wastewater stream 112. The treated water with reduced total dissolved solids is reinjected into the separator 101 as wash water. The reinjection of treated water into the separator 101 provides additional water for washing and diluting the incoming wellhead fluid, improving the efficiency of the initial separation stage while reducing overall water consumption of the desalting system.

As further shown in FIG. 1, the wastewater/water recycle flow/pressure control 119 manages the routing of water within the desalting system. The wastewater/water recycle flow/pressure control 119 directs produced water from the separator 101 to the water treatment unit 111 or to disposal pathways based on operating conditions and water management requirements. The wastewater/water recycle flow/pressure control 119 controls the flow of the reduced-salt water stream 113 from the water treatment unit 111 back to the separator 101 for reuse as wash water. The wastewater/water recycle flow/pressure control 119 receives control signals from the programmable logic controller 200 to adjust water routing based on system operating conditions and water quality parameters.

The wastewater is reinjected into the reservoir associated with the oil well 100 for stimulation purposes. Reinjection of produced water into the reservoir maintains reservoir pressure and enhances oil recovery from the formation. The wastewater is injected into a Class II disposal well designed for disposal of fluids associated with oil and gas production. Class II disposal wells provide a disposal method when reinjection into the production reservoir is not feasible or when regulatory requirements mandate dedicated disposal facilities.

With continued reference to FIG. 1, the wastewater is transported off-site via trucks for treatment or disposal at specialized facilities. Off-site transportation provides a disposal option when on-site treatment or disposal is not practical or when regulatory requirements necessitate management of produced water at facilities equipped for handling oilfield wastewater.

The desalting system includes sensors to monitor water quality parameters of the wastewater throughout the water management process. The sensors measure parameters including salt concentration, pH, turbidity, and other water quality indicators that inform treatment and disposal decisions. The desalting system includes flow meters to measure water volumes of the wastewater at various points within the water management system. The flow meters provide data on water production rates and treatment throughput for process monitoring and control purposes.

The desalting system includes automated valves and pumps to control the routing of water within the system. The automated valves open and close under direction of the programmable logic controller 200 to direct water flow between the separator 101, the water treatment unit 111, and disposal or reuse pathways. The pumps provide motive force to move water through the treatment and routing systems at controlled rates. The programmable logic controller 200 coordinates operation of the automated valves and pumps based on sensor data and programmed control logic to maintain appropriate water management throughout the desalting process.

With continued reference to FIG. 1, a residue gas header collects gaseous hydrocarbons from a separator and a distillation column. The residue gas header receives gaseous hydrocarbon streams that separate from the wellhead fluid during processing operations in the separator and the distillation column. The gaseous hydrocarbons collected by the residue gas header comprise lighter hydrocarbon fractions that vaporize during the separation and stabilization processes. The residue gas header consolidates the gaseous hydrocarbon streams from multiple sources within the desalting system into a single stream for downstream handling and utilization.

The residue gas collected by the residue gas header is used on-site for fuel. The gaseous hydrocarbons provide a fuel source for equipment and operations at the production facility, reducing reliance on external fuel supplies. The residue gas is evacuated to a midstream pipeline for transportation to downstream processing facilities or markets. Pipeline evacuation requires the residue gas to meet quality specifications established by the pipeline operator, which the stabilization process achieves through separation of heavier hydrocarbon fractions and removal of contaminants.

As further shown in FIG. 1, the residue gas is used for gas lift reinjection. Gas lift operations compress the residue gas and reinject the compressed gas into a well to assist in lifting oil to the surface. The reinjection of residue gas for gas lift enhances oil production rates and improves overall field efficiency by utilizing the gaseous hydrocarbons produced during stabilization operations.

The residue gas is treated in a gas sweetening unit to remove hydrogen sulfide and other contaminants before the residue gas is directed to downstream utilization options. The gas sweetening unit processes the residue gas to meet quality specifications for pipeline injection, power generation, or other uses that require removal of sulfur compounds and other impurities. The gas sweetening treatment produces a treated gas stream suitable for applications where untreated residue gas would cause corrosion, environmental emissions, or equipment damage.

With continued reference to FIG. 1, the residue gas is used for on-site power generation using gas-fired generators or turbines. The gas-fired generators or turbines convert the chemical energy in the residue gas into electrical power for use at the production facility. On-site power generation reduces the facility's reliance on external power sources and lowers operational costs by utilizing the gaseous hydrocarbons that would otherwise require disposal or transportation.

The residue gas is directed to a flare system as a safety measure for handling excess gas. The flare system provides a disposal method for residue gas that cannot be processed or utilized through other means. Flaring safely combusts excess gaseous hydrocarbons when production rates exceed the capacity of utilization systems or when equipment malfunctions prevent normal gas handling operations.

As further shown in FIG. 1, the desalting system includes gas composition analyzers to monitor gas quality of the residue gas. The gas composition analyzers measure the concentrations of various hydrocarbon species, hydrogen sulfide, carbon dioxide, and other constituents in the residue gas stream. The composition data from the gas analyzers informs decisions regarding gas routing, treatment requirements, and suitability for various utilization options.

The desalting system includes flow meters to measure gas volumes of the residue gas at various points within the gas handling system. The flow meters provide data on gas production rates and throughput for process monitoring, production accounting, and control purposes. The flow measurement data enables tracking of gas volumes directed to each utilization option and supports optimization of gas management operations.

With continued reference to FIG. 1, the desalting system includes automated valves to control the routing of residue gas to different utilization options. The automated valves open and close under direction of a programmable logic controller to direct residue gas flow between the midstream pipeline, on-site power generation equipment, gas lift operations, and the flare system. The automated valves respond to control signals based on gas quality measurements, flow rates, equipment availability, and operational priorities to route the residue gas to appropriate destinations. The programmable logic controller coordinates operation of the automated valves based on data from the gas composition analyzers and flow meters to maintain appropriate gas management throughout the desalting process.

Referring to FIG. 2, a flowchart shows the process 300 for processing oilfield fluids to produce desalted crude oil. The process 300 integrates separation, stabilization, chemical treatment, and automated monitoring and cleaning operations to produce desalted crude oil while minimizing scaling, salt depositions, and downtime for descaling.

The process 300 begins with a step 302 for receiving wellhead fluid from the oil well 100. The wellhead fluid contains a mixture of hydrocarbons, water, and various impurities such as salts and minerals. The wellhead fluid passes through the pressure regulating valve 107 to regulate the system inlet flow and prepare the wellhead fluid for subsequent processing stages within the desalting system.

With continued reference to FIG. 2, the process 300 proceeds to a step 304 for initial separation of the wellhead fluid into different streams. The step 304 separates the wellhead fluid into wastewater, liquid hydrocarbons, and gaseous hydrocarbons within the separator 101. The interface level sensor 101a monitors the oil-water interface level within the separator 101 during the step 304. The separator 101 uses an electric charge to increase water separation from the oil during the step 304. The separator 101 uses a coalescing media to increase water separation from the oil during the step 304. The system includes sensors to monitor water quality parameters of the wastewater produced during the step 304.

Following the step 304, the process 300 proceeds to a step 306 for directing the liquid hydrocarbons to the stabilization system. The step 306 routes the liquid hydrocarbon stream 110 from the separator 101 to the distillation column 102 for further processing. The liquid hydrocarbon stream 110 exits the separator 101 by spilling over the weir 101b and travels to the distillation column 102.

As further shown in FIG. 2, the process 300 includes a step 308 as the overall processing within the stabilization system. The step 308 encompasses the separation and stabilization operations performed within the distillation column 102 and the reboiler 103. The step 308 produces the stabilized crude oil 115 and gaseous hydrocarbons that exit via the residue gas header 114. The programmable logic controller 200 controls the operation of the stabilization system during the step 308 to maintain appropriate operating conditions and minimize scaling and salt deposition throughout the process 300.

With continued reference to FIG. 2, the process 300 includes a step 310 for chemical injection of desalting and de-emulsion additives into the stabilization system. The step 310 operates in parallel with the main processing flow within the step 308 to enhance the separation of water and impurities from the oil throughout the stabilization process. The chemical injection pump 106 delivers desalting and de-emulsion additives through the injection header 109 at controlled rates during the step 310. The desalting additives break down the bonds between salt compounds and the hydrocarbon matrix, facilitating release of dissolved salts into the water phase for subsequent removal. The de-emulsion additives destabilize water-in-oil emulsions that form during production and transportation of the wellhead fluid, allowing water droplets to coalesce and separate from the hydrocarbon phase.

The step 310 introduces the desalting and de-emulsion additives at multiple locations within the stabilization system. The additives are introduced before the wellhead fluid enters the separator 101 to begin the desalting and de-emulsification processes during the initial separation in the step 304. The additives are introduced into the distillation column 102 to continue the desalting and de-emulsification processes during the separation operations in a step 312. The additives are introduced into the reboiler 103 to address residual emulsions and salt compounds that persist through earlier processing stages. The programmable logic controller 200 controls the chemical injection pump 106 to regulate the rate and timing of additive injection based on process conditions and the characteristics of the wellhead fluid being processed.

As further shown in FIG. 2, the step 312 separates the hydrocarbon stream in the distillation column 102. The step 312 receives the liquid hydrocarbon stream 110 from the separator 101 and further separates the hydrocarbons based on boiling points within the distillation column 102. The distillation column 102 operates at elevated temperatures that cause lighter hydrocarbon fractions to vaporize and rise through the column while heavier fractions remain in liquid form and descend toward the lower region of the distillation column 102. The interface level sensor 102a monitors water buildup within the distillation column 102 during the step 312 and provides data to the programmable logic controller 200 for control of water evacuation operations.

The step 312 causes saline water to accumulate in the lower region of the distillation column 102 due to the density difference between the saline water and the lighter hydrocarbon liquids. The weir 102b within the distillation column 102 allows lighter liquid hydrocarbons to flow over while denser saline water collects behind the weir 102b. The distillation column water evacuation pump 117 and the distillation column water evacuation valve 122 remove accumulated saline water from the lower region of the distillation column 102 during the step 312. The removal of saline water from the distillation column 102 prevents the saline water from entering the reboiler 103 and accumulating on the heating element 116.

With continued reference to FIG. 2, a step 314 vaporizes volatile components in the reboiler 103. The step 314 receives hydrocarbon liquids from the distillation column 102 and applies heat through the heating element 116 to vaporize lighter hydrocarbon fractions. The vaporized hydrocarbons return to the distillation column 102 to enhance the separation of components based on boiling points during the step 312. The heavier hydrocarbon fractions remain in liquid form within the reboiler 103 and exit as the stabilized crude oil 115.

The step 314 operates in coordination with the step 312 to achieve the desired separation of hydrocarbon components within the stabilization system. The heating element 116 transfers thermal energy to the hydrocarbon liquids within the reboiler 103 at temperatures sufficient to drive off volatile components while maintaining the heavier hydrocarbon fractions in liquid form. The interface level sensor 103a monitors water buildup within the reboiler 103 during the step 314 and provides data to the programmable logic controller 200 for monitoring and control of water levels. The reboiler water/oil evacuation pump 104 and the reboiler water evacuation valve 121 remove any water that accumulates within the reboiler 103 during the step 314.

As further shown in FIG. 2, the step 310, the step 312, and the step 314 work together within the step 308 to produce the stabilized crude oil 115 with reduced salt content. The step 310 introduces desalting and de-emulsion additives that facilitate release of dissolved salts into the water phase and promote coalescence of water droplets for separation from the hydrocarbon phase. The step 312 separates the hydrocarbon stream in the distillation column 102 based on boiling points while causing saline water to accumulate in the lower region of the distillation column 102 for removal. The step 314 vaporizes volatile components in the reboiler 103 to stabilize the crude oil while the vertical positioning of the reboiler 103 relative to the distillation column 102 inhibits saline water from accumulating within the reboiler 103.

The programmable logic controller 200 coordinates the operation of the step 310, the step 312, and the step 314 throughout the process 300. The programmable logic controller 200 controls the chemical injection pump 106 during the step 310 to regulate additive injection rates based on process conditions. The programmable logic controller 200 controls the distillation column water evacuation pump 117 and the distillation column water evacuation valve 122 during the step 312 based on data from the interface level sensor 102a. The programmable logic controller 200 controls the heating element 116, the reboiler water/oil evacuation pump 104, and the reboiler water evacuation valve 121 during the step 314 based on data from the interface level sensor 103a. The gaseous hydrocarbons produced during the step 312 and the step 314 exit via the residue gas header 114 for downstream utilization.

With continued reference to FIG. 2, the process 300 includes a step 316 for detecting accumulation of salty water in the distillation column 102 or the reboiler 103. The step 316 operates in parallel with the processing operations within the step 308 to monitor water levels throughout the stabilization system. The interface level sensor 102a detects accumulation of salty water in the distillation column 102 during the step 316. The interface level sensor 103a detects accumulation of salty water in the reboiler 103 during the step 316. The programmable logic controller 200 receives data from the interface level sensor 102a and the interface level sensor 103a during the step 316 to determine when salty water accumulation exceeds specified thresholds.

The step 316 provides input to the step 312 within the step 308 processing block. The detection of salty water accumulation in the distillation column 102 during the step 316 triggers water evacuation operations that maintain appropriate operating conditions during the separation operations in the step 312. The programmable logic controller 200 compares the water level data from the interface level sensor 102a and the interface level sensor 103a against configurable threshold values during the step 316 to identify conditions requiring remedial action.

As further shown in FIG. 2, the process 300 includes a step 318 for automatically evacuating the salty water from affected components. The step 318 follows the step 316 when the programmable logic controller 200 determines that salty water accumulation exceeds specified thresholds. The step 318 provides input to the step 314 within the step 308 processing block. The programmable logic controller 200 initiates the step 318 by opening the distillation column water evacuation valve 122 and activating the distillation column water evacuation pump 117 to remove accumulated salty water from the lower region of the distillation column 102.

The step 318 removes accumulated salty water from the reboiler 103 when the interface level sensor 103a detects water accumulation within the reboiler 103. The programmable logic controller 200 opens the reboiler water evacuation valve 121 and activates the reboiler water/oil evacuation pump 104 during the step 318 to evacuate salty water that collects behind the weir 103b. The automated evacuation during the step 318 maintains optimal operating conditions within the distillation column 102 and the reboiler 103 while minimizing disruption to the overall process 300.

With continued reference to FIG. 2, the process 300 includes a step 320 for monitoring signs of salt, scale, or other fouling accumulation within the stabilization system. The step 320 operates continuously during the process 300 to detect conditions that indicate fouling buildup on internal surfaces of the separator 101, the distillation column 102, and the reboiler 103. The programmable logic controller 200 monitors operating parameters including temperature, pressure, and flow rates throughout the stabilization system during the step 320. The programmable logic controller 200 detects increased pressure drop across the distillation column 102 during the step 320 as indicative of blockage caused by salt accumulation and scaling.

The step 320 monitors power consumption of the heating element 116 and temperature in the reboiler 103 to determine when power requirements increase indicating salt and scale accumulation on the heating element 116. Chemical sensors monitor the composition of the outgoing stabilized hydrocarbon stream during the step 320 to allow the programmable logic controller 200 to detect salt content over specified thresholds. The programmable logic controller 200 uses machine learning during the step 320 to aid in determining when sensor input indicates that a condition exists where remedial action is to be taken.

As further shown in FIG. 2, the process 300 includes a step 322 as a decision step for determining whether accumulation is detected. The step 322 follows the step 320 and evaluates the monitoring data collected during the step 320 to determine whether salt, scale, or other fouling accumulation has reached levels requiring remedial action. The programmable logic controller 200 compares the monitored parameters against configurable thresholds during the step 322 to identify patterns indicative of fouling problems within the stabilization system.

The step 322 produces a No branch that returns to the step 320 for continued monitoring when the programmable logic controller 200 determines that monitored parameters remain within acceptable ranges. The step 322 produces a Yes branch that proceeds to a step 324 when the programmable logic controller 200 determines that monitored parameters indicate fouling accumulation requiring remedial action. The decision logic within the step 322 evaluates multiple parameters including pressure drop, power consumption, temperature profiles, and chemical composition data to determine whether fouling conditions exist.

With continued reference to FIG. 2, the step 324 triggers remedial action such as hot oil recycling or steam cleaning when the step 322 determines that fouling accumulation is detected. The programmable logic controller 200 initiates the step 324 by activating cleaning operations through the cleaning header 108 to address the detected fouling conditions. The step 324 circulates heated hydrocarbon fluid through the reboiler 103 to dissolve and remove salt deposits and other fouling materials from internal surfaces including the heating element 116.

The step 324 introduces steam through the cleaning header 108 into the separator 101, the distillation column 102, and the reboiler 103 for steam cleaning operations. The step 324 introduces chemical descaling agents through the cleaning header 108 to address fouling that cannot be removed through hot oil circulation or steam cleaning alone. The programmable logic controller 200 selects the appropriate remedial action during the step 324 based on the type and severity of fouling detected during the step 320 and the step 322.

The step 324 issues a message to the operator through the operator interface 202 recommending external hot oil wash when the programmable logic controller 200 determines that internal cleaning operations are insufficient to address the detected fouling. The programmable logic controller 200 sends notification to the operator through the operator interface 202 that external hot oil wash is recommended based on the configurable timer 204. The programmable logic controller 200 sends notification to the operator that a comprehensive refurbish is recommended based on the configurable timer 204 or if performance degrades below a certain configurable threshold during the step 324.

Referring to FIG. 3, a schematic diagram of the programmable logic controller 200 and related components is illustrated. The programmable logic controller 200 serves as the central control unit for the desalting system and receives input from multiple sensors throughout the system. The programmable logic controller 200 receives input from the interface level sensor 101a for monitoring the oil-water interface level within the separator 101. The programmable logic controller 200 receives input from the interface level sensor 102a for monitoring the oil-water interface level within the distillation column 102. The programmable logic controller 200 receives input from the interface level sensor 103a for monitoring the oil-water interface level within the reboiler 103. The interface level sensors 101a, 102a, and 103a provide data to the programmable logic controller 200 that enables automated control of water evacuation processes throughout the desalting system.

As further shown in FIG. 3, the programmable logic controller 200 connects to additional sensors labeled S1 through Sn that provide further monitoring capabilities throughout the desalting system. The additional sensors S1 through Sn monitor operating parameters at various locations within the desalting system including pressure, temperature, liquid level, level of interface between two liquids of differing density, flow rate, and chemical composition. The programmable logic controller 200 receives data from the additional sensors S1 through Sn and processes the data to determine operating conditions throughout the desalting system. The additional sensors S1 through Sn enable the programmable logic controller 200 to detect conditions requiring remedial action such as salt accumulation, scale buildup, or other fouling within the separator 101, the distillation column 102, and the reboiler 103.

With continued reference to FIG. 3, communication between the programmable logic controller 200 and sensors or controlled devices is wired. Wired communication provides reliable signal transmission between the programmable logic controller 200 and the interface level sensor 101a, the interface level sensor 102a, the interface level sensor 103a, and the additional sensors S1 through Sn. Wired connections carry sensor data from the sensors to the programmable logic controller 200 and carry control instructions from the programmable logic controller 200 to controlled devices throughout the desalting system.

Communication between the programmable logic controller 200 and sensors or controlled devices is wireless. Wireless communication enables signal transmission between the programmable logic controller 200 and sensors or controlled devices without physical cable connections. Wireless communication provides flexibility in sensor placement and reduces installation complexity for sensors located in areas where wired connections are difficult to route. The programmable logic controller 200 receives sensor data and transmits control instructions through wireless communication links to sensors and controlled devices throughout the desalting system.

With continued reference to FIG. 3, the programmable logic controller 200 communicates with and controls multiple devices throughout the desalting system. The programmable logic controller 200 transmits control instructions to the reboiler water/oil evacuation pump 104 to regulate the evacuation of water and oil from the reboiler 103. The reboiler water/oil evacuation pump 104 receives control signals from the programmable logic controller 200 that activate the pump, adjust pump speed, and deactivate the pump based on water level data from the interface level sensor 103a. The programmable logic controller 200 coordinates operation of the reboiler water/oil evacuation pump 104 with the reboiler water evacuation valve 121 to control the timing and rate of water evacuation from the reboiler 103.

The programmable logic controller 200 transmits control instructions to the separator water evacuation pump 105 to regulate the removal of produced water from the separator 101. The separator water evacuation pump 105 operates under direction of the programmable logic controller 200 to evacuate water that accumulates behind the weir 101b within the separator 101. The programmable logic controller 200 activates the separator water evacuation pump 105 based on data from the interface level sensor 101a indicating that water levels within the separator 101 exceed specified thresholds.

As further shown in FIG. 3, the programmable logic controller 200 transmits control instructions to the chemical injection pump 106 to regulate the delivery of desalting and de-emulsion additives into the desalting system. The chemical injection pump 106 receives control signals from the programmable logic controller 200 that adjust the injection rate of chemicals through the injection header 109. The programmable logic controller 200 controls the chemical injection pump 106 based on process conditions including flow rates, water content measurements, and salt concentration data to maintain appropriate additive dosing throughout the desalting process.

The programmable logic controller 200 transmits control instructions to the pressure regulating valve 107 to regulate the system inlet flow. The pressure regulating valve 107 receives control signals from the programmable logic controller 200 that adjust the valve position to maintain appropriate pressure conditions for wellhead fluid entering the desalting system. The programmable logic controller 200 monitors inlet pressure and flow rate data and adjusts the pressure regulating valve 107 to maintain stable operating conditions within the separator 101 and downstream components.

With continued reference to FIG. 3, the programmable logic controller 200 transmits control instructions to the cleaning header 108 to initiate and control cleaning operations within the desalting system. The cleaning header 108 receives control signals from the programmable logic controller 200 that open valves to introduce steam, hot oil, or chemical descaling agents into the separator 101, the distillation column 102, and the reboiler 103. The programmable logic controller 200 activates the cleaning header 108 in response to detected fouling conditions or based on scheduled maintenance intervals established through the configurable timer 204.

The programmable logic controller 200 transmits control instructions to the heating element 116 to regulate the heat input to the reboiler 103. The heating element 116 receives control signals from the programmable logic controller 200 that adjust the power delivered to the heating element 116 to maintain appropriate temperatures within the reboiler 103 for vaporizing volatile hydrocarbon components. The programmable logic controller 200 monitors temperature data from sensors within the reboiler 103 and adjusts the heating element 116 to maintain optimal distillation conditions while minimizing energy consumption.

As further shown in FIG. 3, the programmable logic controller 200 transmits control instructions to the distillation column water evacuation pump 117 to regulate the removal of accumulated saline water from the lower region of the distillation column 102. The distillation column water evacuation pump 117 receives control signals from the programmable logic controller 200 that activate the pump based on water level data from the interface level sensor 102a. The programmable logic controller 200 coordinates operation of the distillation column water evacuation pump 117 with the distillation column water evacuation valve 122 to control the timing and rate of water evacuation from the distillation column 102.

The programmable logic controller 200 transmits control instructions to the desalted crude flow/pressure control 118 to regulate the output of the stabilized crude oil 115 from the reboiler 103. The desalted crude flow/pressure control 118 receives control signals from the programmable logic controller 200 that adjust flow rate and pressure parameters for the stabilized crude oil 115 exiting the desalting system. The programmable logic controller 200 monitors production rates and downstream conditions and adjusts the desalted crude flow/pressure control 118 to maintain consistent delivery of the stabilized crude oil 115.

With continued reference to FIG. 3, the programmable logic controller 200 transmits control instructions to the wastewater/water recycle flow/pressure control 119 to regulate the routing of water within the desalting system. The wastewater/water recycle flow/pressure control 119 receives control signals from the programmable logic controller 200 that direct produced water from the separator 101 to the water treatment unit 111 or to disposal pathways. The programmable logic controller 200 controls the wastewater/water recycle flow/pressure control 119 to route the reduced-salt water stream 113 from the water treatment unit 111 back to the separator 101 for reuse as wash water based on water quality parameters and system operating conditions.

The programmable logic controller 200 transmits control instructions to the reboiler water evacuation valve 121 to control water evacuation from the reboiler 103. The reboiler water evacuation valve 121 receives control signals from the programmable logic controller 200 that open and close the valve based on water level data from the interface level sensor 103a. The programmable logic controller 200 coordinates operation of the reboiler water evacuation valve 121 with the reboiler water/oil evacuation pump 104 to remove accumulated water from behind the weir 103b within the reboiler 103.

As further shown in FIG. 3, the programmable logic controller 200 transmits control instructions to the distillation column water evacuation valve 122 to control water evacuation from the distillation column 102. The distillation column water evacuation valve 122 receives control signals from the programmable logic controller 200 that open and close the valve based on water level data from the interface level sensor 102a. The programmable logic controller 200 coordinates operation of the distillation column water evacuation valve 122 with the distillation column water evacuation pump 117 to remove accumulated saline water from the lower region of the distillation column 102.

The programmable logic controller 200 connects to additional controlled devices labeled D1 through Dn that perform various functions throughout the desalting system. The additional controlled devices D1 through Dn receive control instructions from the programmable logic controller 200 and report operating status data back to the programmable logic controller 200. The programmable logic controller 200 coordinates operation of the additional controlled devices D1 through Dn with the other controlled devices to maintain appropriate operating conditions throughout the desalting process.

With continued reference to FIG. 3, the operator interface 202 presents information to an operator and allows the operator to provide input to the programmable logic controller 200. The operator interface 202 displays operating parameters, alarm conditions, and system status information collected by the programmable logic controller 200 from sensors throughout the desalting system. The operator interface 202 receives input from the operator including setpoint adjustments, manual control commands, and acknowledgment of alarm conditions. The programmable logic controller 200 processes operator input received through the operator interface 202 and adjusts control of the desalting system based on the operator input.

The operator interface 202 is provided at least in part by appropriate software running on a mobile computing device used by the operator. The software running on the mobile computing device communicates with the programmable logic controller 200 to display system information and transmit operator input. The mobile computing device enables the operator to monitor and control the desalting system from locations remote from the programmable logic controller 200. The operator interface 202 displays notifications from the programmable logic controller 200 including recommendations for external hot oil wash based on the configurable timer 204 and recommendations for comprehensive refurbishment based on performance degradation below configurable thresholds.

With continued reference to FIG. 3, the configurable timer 204 connects to the programmable logic controller 200 and triggers periodic maintenance notifications based on predetermined time intervals. The configurable timer 204 tracks elapsed operating time of the desalting system and generates timer signals when the elapsed time reaches configured threshold values. The programmable logic controller 200 receives the timer signals from the configurable timer 204 and initiates notification processes to inform the operator of recommended maintenance actions.

The configurable timer 204 stores one or more time interval values that define the periods between maintenance notifications. The time interval values are adjustable to accommodate different operating conditions, wellhead fluid characteristics, and maintenance requirements for the desalting system. The programmable logic controller 200 accesses the time interval values stored in the configurable timer 204 and compares the elapsed operating time against the stored values to determine when maintenance notifications are to be generated.

As further shown in FIG. 3, the programmable logic controller 200 sends notification to the operator through the operator interface 202 that external hot oil wash is recommended based on the configurable timer 204. The notification informs the operator that the predetermined time interval for external hot oil wash has elapsed and that maintenance action is recommended to address potential fouling accumulation within the separator 101, the distillation column 102, and the reboiler 103. The operator interface 202 displays the notification to the operator and records the notification for maintenance tracking purposes.

The timer-based notification approach ensures regular maintenance is performed even in the absence of detected performance issues. The configurable timer 204 provides a scheduled maintenance framework that supplements the condition-based monitoring performed by the programmable logic controller 200 through the interface level sensor 101a, the interface level sensor 102a, the interface level sensor 103a, and other sensors throughout the desalting system. The combination of timer-based and condition-based maintenance notifications enables comprehensive maintenance management for the desalting system.

With continued reference to FIG. 3, the programmable logic controller 200 sends notification to the operator through the operator interface 202 that a comprehensive refurbish is recommended based on the configurable timer 204. The comprehensive refurbish notification indicates that the predetermined time interval for thorough system maintenance has elapsed and that refurbishment operations are recommended to remove accumulated salt, scale, and other fouling from the reboiler 103 and the distillation column 102. The configurable timer 204 stores a separate time interval value for comprehensive refurbishment that is longer than the time interval for external hot oil wash, reflecting the more extensive nature of refurbishment operations.

The programmable logic controller 200 sends notification to the operator through the operator interface 202 that a comprehensive refurbish is recommended if performance degrades below a certain configurable threshold. The programmable logic controller 200 monitors operating parameters throughout the desalting system and compares the parameters against configurable threshold values to detect performance degradation. When the monitored parameters indicate that system performance has degraded below the configurable threshold, the programmable logic controller 200 generates a comprehensive refurbish notification regardless of the elapsed time tracked by the configurable timer 204. The performance-based notification ensures that maintenance is performed when operating conditions indicate fouling accumulation has reached levels affecting system efficiency, even if the scheduled maintenance interval has not yet elapsed.

With continued reference to FIG. 3, the programmable logic controller 200 performs automated detection and control functions for managing salty water accumulation and fouling conditions throughout the desalting system. The programmable logic controller 200 receives data from the interface level sensor 101a, the interface level sensor 102a, and the interface level sensor 103a to detect accumulation of salty water within the separator 101, the distillation column 102, and the reboiler 103. The programmable logic controller 200 compares the water level data from the interface level sensors against configurable threshold values stored in the programmable logic controller 200. When the water level data indicates that salty water accumulation exceeds the configurable threshold values, the programmable logic controller 200 automatically initiates evacuation processes to remove the accumulated salty water from the affected components.

The programmable logic controller 200 initiates evacuation of salty water from the distillation column 102 by transmitting control instructions to the distillation column water evacuation valve 122 and the distillation column water evacuation pump 117. The distillation column water evacuation valve 122 opens in response to the control instructions from the programmable logic controller 200, and the distillation column water evacuation pump 117 activates to remove accumulated salty water from the lower region of the distillation column 102. The programmable logic controller 200 monitors the interface level sensor 102a during the evacuation process and deactivates the distillation column water evacuation pump 117 and closes the distillation column water evacuation valve 122 when the water level returns to within acceptable operating ranges.

As further shown in FIG. 3, the programmable logic controller 200 initiates evacuation of salty water from the reboiler 103 by transmitting control instructions to the reboiler water evacuation valve 121 and the reboiler water/oil evacuation pump 104. The reboiler water evacuation valve 121 opens in response to the control instructions from the programmable logic controller 200, and the reboiler water/oil evacuation pump 104 activates to remove accumulated water from behind the weir 103b within the reboiler 103. The programmable logic controller 200 monitors the interface level sensor 103a during the evacuation process and adjusts the operation of the reboiler water/oil evacuation pump 104 and the reboiler water evacuation valve 121 based on the water level data to maintain appropriate operating conditions within the reboiler 103.

With continued reference to FIG. 3, the programmable logic controller 200 detects accumulation of salts, scale, or other fouling in the desalting system and triggers recycling of hot oil in the system. The programmable logic controller 200 monitors operating parameters from sensors throughout the desalting system to identify conditions indicative of fouling accumulation on internal surfaces of the separator 101, the distillation column 102, and the reboiler 103. When the programmable logic controller 200 detects fouling accumulation based on the monitored operating parameters, the programmable logic controller 200 activates hot oil recycling through the cleaning header 108 to circulate heated hydrocarbon fluid through the affected components. The hot oil recycling dissolves and removes salt deposits and other fouling materials from internal surfaces including the heating element 116 within the reboiler 103.

The programmable logic controller 200 detects that the distillation system efficiency has decreased and issues a message to the operator through the operator interface 202 recommending external hot oil wash. The programmable logic controller 200 calculates system efficiency based on operating parameters including throughput rates, energy consumption, product quality measurements, and separation performance indicators. When the calculated system efficiency falls below a configurable threshold value stored in the programmable logic controller 200, the programmable logic controller 200 generates a notification message and transmits the notification message to the operator interface 202. The notification message informs the operator that external hot oil wash is recommended to address fouling conditions that internal cleaning operations cannot adequately resolve.

As further shown in FIG. 3, the programmable logic controller 200 uses machine learning to aid in determining when sensor input indicates that a condition exists where remedial action is to be taken. The programmable logic controller 200 processes historical sensor data and correlates the historical sensor data with known fouling events and maintenance outcomes to develop predictive models for fouling detection. The machine learning algorithms within the programmable logic controller 200 analyze patterns in the sensor data from the interface level sensor 101a, the interface level sensor 102a, the interface level sensor 103a, and additional sensors throughout the desalting system to identify conditions that precede fouling accumulation. The programmable logic controller 200 applies the predictive models to current sensor data to determine when remedial action is to be initiated, enabling proactive maintenance before fouling accumulation reaches levels that significantly impact system performance.

Referring to FIG. 1, the programmable logic controller 200 detects increased pressure drop across the distillation column 102 as indicative of blockage caused by salt accumulation and scaling. The programmable logic controller 200 receives pressure data from pressure sensors positioned at the inlet and outlet of the distillation column 102. The programmable logic controller 200 calculates the pressure differential across the distillation column 102 by subtracting the outlet pressure from the inlet pressure. When the calculated pressure differential exceeds a configurable threshold value, the programmable logic controller 200 determines that blockage caused by salt accumulation and scaling is present within the distillation column 102. The programmable logic controller 200 initiates remedial action in response to the detected pressure drop increase, including activation of hot oil recycling through the cleaning header 108 or generation of maintenance notifications through the operator interface 202.

With continued reference to FIG. 1, the programmable logic controller 200 monitors power consumption of the heating element 116 and temperature in the reboiler 103 to determine that power requirement has increased indicating salt and scale accumulation on the heating element 116. The programmable logic controller 200 receives power consumption data from sensors monitoring the electrical input to the heating element 116. The programmable logic controller 200 receives temperature data from temperature sensors positioned within the reboiler 103. The programmable logic controller 200 correlates the power consumption data with the temperature data to calculate the thermal efficiency of the heating element 116. When the power consumption required to maintain a specified temperature within the reboiler 103 increases beyond a configurable threshold, the programmable logic controller 200 determines that salt and scale accumulation on the heating element 116 is reducing heat transfer efficiency. The programmable logic controller 200 initiates remedial action including hot oil recycling, notification to the operator for heating element 116 cleaning or replacement, or activation of ultrasonic cleaning devices to remove the accumulated deposits from the heating element 116.

As further shown in FIG. 1, chemical sensors monitor the composition of the outgoing stabilized hydrocarbon stream to allow the programmable logic controller 200 to detect a salt content over a specified threshold. The chemical sensors analyze the stabilized crude oil 115 exiting the reboiler 103 and measure the concentration of salt compounds remaining in the stabilized crude oil 115. The chemical sensors transmit composition data to the programmable logic controller 200 for comparison against configurable salt content threshold values. When the measured salt content exceeds the specified threshold, the programmable logic controller 200 determines that the desalting process is not achieving adequate salt removal and initiates corrective action. The corrective action includes increasing the injection rate of desalting additives through the chemical injection pump 106, activating additional water washing operations, or generating notifications through the operator interface 202 recommending system inspection and maintenance.

Referring to FIG. 3, the desalting system incorporates online analyzers to continuously monitor the salt content of the crude oil at various stages of the process. The online analyzers are positioned at multiple locations within the desalting system including downstream of the separator 101, within the distillation column 102, and at the output of the reboiler 103. The online analyzers provide real-time salt concentration measurements to the programmable logic controller 200 throughout the desalting process. The programmable logic controller 200 uses the salt concentration data from the online analyzers to adjust process parameters including chemical injection rates, operating temperatures, and water evacuation timing to optimize salt removal performance.

With continued reference to FIG. 1, the desalting system includes a salt recovery unit to process the concentrated brine and recover valuable minerals as a byproduct. The salt recovery unit receives the concentrated brine removed from the separator 101, the distillation column 102, and the reboiler 103 through the water evacuation systems. The salt recovery unit processes the concentrated brine to extract dissolved minerals and salt compounds for recovery and sale as byproducts. The recovered materials offset operational costs of the desalting process and reduce the volume of waste requiring disposal.

The desalting system includes heat integration between hot and cold streams to reduce external energy requirements for heating and cooling. Heat exchangers transfer thermal energy from hot process streams to cold process streams within the desalting system. The heat integration recovers thermal energy from the stabilized crude oil 115 exiting the reboiler 103 and transfers the recovered thermal energy to the incoming wellhead fluid or other cold streams requiring heating. The heat integration reduces the energy input required for the heating element 116 and reduces the cooling load for the stabilized crude oil 115 before the product manifold.

With continued reference to FIG. 1, the desalting system includes alternative flow control configurations where flow between various components is controlled by valves alone using gravity and pressure to motivate the flow instead of pumps. The separator 101 is positioned at an elevation above the distillation column 102 such that the liquid hydrocarbon stream 110 flows from the separator 101 to the distillation column 102 under the influence of gravity without requiring a pump. The valve 124 controls the flow rate of the liquid hydrocarbon stream 110 between the separator 101 and the distillation column 102 by adjusting the valve opening to regulate the gravitational flow. The programmable logic controller 200 transmits control instructions to the valve 124 to adjust the valve position based on flow rate requirements and operating conditions within the distillation column 102.

The distillation column 102 is positioned at an elevation relative to the reboiler 103 such that hydrocarbon liquids flow between the distillation column 102 and the reboiler 103 under the influence of gravity and pressure differentials created during the distillation process. The pressure within the distillation column 102 drives vapor flow from the reboiler 103 back into the distillation column 102 without requiring mechanical pumping. The valve 120 controls the flow of hydrocarbon liquids from the distillation column 102 to the reboiler 103 by adjusting the valve opening to regulate the gravity-driven and pressure-driven flow between the two components.

As further shown in FIG. 1, the reboiler 103 is positioned such that the stabilized crude oil 115 flows from the reboiler 103 to the product manifold under the influence of pressure within the reboiler 103 and gravity. The desalted crude flow/pressure control 118 regulates the flow of the stabilized crude oil 115 from the reboiler 103 without requiring a dedicated pump by controlling the valve opening to allow pressure-driven flow from the reboiler 103. The pressure generated by vaporization of volatile components within the reboiler 103 provides motive force for the stabilized crude oil 115 to exit the reboiler 103 and travel toward downstream equipment.

The wastewater stream 112 flows from the separator 101 to disposal or to the water treatment unit 111 under the influence of gravity when the separator 101 is positioned at an elevation above the disposal point or the water treatment unit 111. The wastewater/water recycle flow/pressure control 119 regulates the gravity-driven flow of the wastewater stream 112 by adjusting valve positions to control the flow rate without requiring the separator water evacuation pump 105. The reduced-salt water stream 113 flows from the water treatment unit 111 back to the separator 101 under pressure generated by the water treatment unit 111 or under gravity when the water treatment unit 111 is positioned at an appropriate elevation relative to the separator 101.

With continued reference to FIG. 1, the residue gas header 114 collects gaseous hydrocarbons from the separator 101 and the distillation column 102 under the influence of pressure differentials within the desalting system. The valve 123 controls the flow of residue gas through the residue gas header 114 by adjusting the valve opening to regulate the pressure-driven flow of gaseous hydrocarbons to downstream utilization options. The gaseous hydrocarbons flow through the residue gas header 114 without requiring compression or pumping when the pressure within the separator 101 and the distillation column 102 exceeds the pressure at the downstream destination.

The cleaning header 108 introduces steam, hot oil, or chemical descaling agents into the separator 101, the distillation column 102, and the reboiler 103 under pressure from external sources without requiring dedicated pumps within the desalting system. The pressure of the steam supply, hot oil supply, or chemical supply provides motive force for the cleaning agents to flow through the cleaning header 108 and into the components being cleaned. Valves associated with the cleaning header 108 control the introduction of cleaning agents by opening and closing under direction of the programmable logic controller 200.

As further shown in FIG. 1, the injection header 109 delivers desalting and de-emulsion additives from the chemical injection pump 106 into the desalting system. In alternative configurations, the chemical injection pump 106 is replaced by a pressurized chemical supply vessel that provides motive force for the chemicals to flow through the injection header 109 under pressure without mechanical pumping. A valve associated with the injection header 109 controls the flow rate of chemicals by adjusting the valve opening to regulate the pressure-driven flow of additives into the wellhead fluid.

Referring to FIG. 3, the programmable logic controller 200 controls the valves throughout the desalting system to regulate gravity-driven and pressure-driven flow between components. The programmable logic controller 200 receives flow rate data from flow sensors positioned throughout the desalting system and adjusts valve positions to maintain appropriate flow rates without relying on pumps for flow motivation. The programmable logic controller 200 coordinates operation of the valve 120, the valve 123, the valve 124, the reboiler water evacuation valve 121, the distillation column water evacuation valve 122, the desalted crude flow/pressure control 118, and the wastewater/water recycle flow/pressure control 119 to maintain appropriate flow conditions throughout the desalting system using gravity and pressure as the primary motive forces.

With continued reference to FIG. 1, pumps are included in the desalting system where gravity and pressure alone are not practical for a particular configuration. The reboiler water/oil evacuation pump 104 is included when the reboiler 103 is positioned such that gravity alone cannot motivate flow of accumulated water from behind the weir 103b to the disposal or recycle destination. The separator water evacuation pump 105 is included when the separator 101 is positioned such that gravity alone cannot motivate flow of the wastewater stream 112 to the water treatment unit 111 or disposal point. The distillation column water evacuation pump 117 is included when the distillation column 102 is positioned such that gravity alone cannot motivate flow of accumulated saline water from the lower region of the distillation column 102 to the disposal or recycle destination.

The chemical injection pump 106 is included when the pressure of the chemical supply is insufficient to motivate flow of desalting and de-emulsion additives through the injection header 109 at the required injection rates. The chemical injection pump 106 provides positive displacement of chemicals into the wellhead fluid stream when pressure-driven injection from a pressurized supply vessel is not practical due to the pressure conditions within the desalting system or the viscosity characteristics of the chemical additives.

As further shown in FIG. 3, the programmable logic controller 200 controls both valve-based flow regulation and pump-based flow motivation depending on the configuration of the desalting system. The programmable logic controller 200 activates pumps when sensors indicate that gravity-driven and pressure-driven flow is insufficient to maintain appropriate operating conditions. The programmable logic controller 200 deactivates pumps and relies on valve-based flow control when gravity and pressure provide adequate motive force for the required flow rates. The programmable logic controller 200 adjusts the balance between valve-based and pump-based flow control based on real-time operating conditions monitored through the interface level sensor 101a, the interface level sensor 102a, the interface level sensor 103a, and additional sensors throughout the desalting system.

FIG. 1 is a schematic diagram of an oilfield fluid processing system for processing wellhead fluid from the oil well 100. The oilfield fluid processing system includes the separator 101, the distillation column 102, and the reboiler 103. The separator 101 includes the interface level sensor 101a and the weir 101b. The distillation column 102 includes the interface level sensor 102a and the weir 102b. The reboiler 103 includes the interface level sensor 103a and the weir 103b. The oilfield fluid processing system includes the reboiler water/oil evacuation pump 104, the separator water evacuation pump 105, the chemical injection pump 106, the pressure regulating valve 107, the cleaning header 108, the injection header 109, the liquid hydrocarbon stream 110, the water treatment unit 111, the wastewater stream 112, the reduced-salt water stream 113, the residue gas header 114, the stabilized crude oil 115, the heating element 116, the distillation column water evacuation pump 117, the desalted crude flow/pressure control 118, the wastewater/water recycle flow/pressure control 119, the valve 120, the reboiler water evacuation valve 121, the distillation column water evacuation valve 122, the valve 123, the valve 124, and the programmable logic controller 200.

FIG. 2 is a flowchart of the process 300 for processing oilfield fluids to produce desalted crude oil. The process 300 includes the step 302 for receiving wellhead fluid, the step 304 for initial separation of the wellhead fluid, the step 306 for directing liquid hydrocarbons to the stabilization system, the step 308 for overall processing within the stabilization system, the step 310 for chemical injection of desalting and de-emulsion additives, the step 312 for separating the hydrocarbon stream in the distillation column, the step 314 for vaporizing volatile components in the reboiler, the step 316 for detecting accumulation of salty water, the step 318 for automatically evacuating the salty water, the step 320 for monitoring signs of salt, scale, or other fouling accumulation, the step 322 for determining whether accumulation is detected, and the step 324 for triggering remedial action.

FIG. 3 is a schematic diagram of the programmable logic controller 200 and related components. FIG. 3 includes the interface level sensor 101a, the interface level sensor 102a, the interface level sensor 103a, the reboiler water/oil evacuation pump 104, the separator water evacuation pump 105, the chemical injection pump 106, the pressure regulating valve 107, the cleaning header 108, the heating element 116, the distillation column water evacuation pump 117, the desalted crude flow/pressure control 118, the wastewater/water recycle flow/pressure control 119, the reboiler water evacuation valve 121, the distillation column water evacuation valve 122, the programmable logic controller 200, the operator interface 202, and the configurable timer 204.

The separator 101 uses an electric charge to increase water separation from the oil. The separator 101 uses a coalescing media to increase water separation from the oil. The separator 101 is back pressure controlled. The separator 101 is a horizontal separator instead of a vertical one for handling fluids with high gas-to-liquid ratios or for installations with height restrictions. The system includes a pre-flash drum before the separator 101 to remove the lightest components of the wellhead fluid. The system employs centrifugal separators or hydrocyclones to enhance the separation of water and oil. The system includes electrostatic coalescers to promote coalescence of water droplets and facilitate their separation from the oil.

The distillation column 102 is randomly packed with materials such as ceramic rings, metal saddles, or structured packing. The distillation column 102 is equipped with trays such as bubble cap trays, sieve trays, or valve trays.

A special coating is used on the heating element 116 of the reboiler 103, the surface of the reboiler 103 vessel, the distillation column 102, and pipes to prevent nucleation of salt deposits or enable easy cleanout. The special coating has a smooth, non-porous surface that reduces the likelihood of salt crystals nucleating and growing on the coated surfaces. The special coating has low surface energy to discourage adhesion of salt deposits. The special coating has non-stick properties that allow salt deposits or other fouling materials to be more easily removed during cleaning processes.

The reboiler 103 is equipped with a flange that enables the extraction of the heating element 116 for thorough cleaning or replacement. The reboiler 103 uses a kettle-type design instead of a traditional shell-and-tube design for improved fouling resistance and ease of maintenance. The reboiler 103 uses direct-fired heaters instead of steam heating. The reboiler 103 uses electric heating elements instead of steam heating.

The stabilized crude oil 115 is cooled before the product manifold using a heat exchanger. The stabilized crude oil 115 is cooled using air coolers instead of or in addition to liquid-based heat exchangers.

The residue gas collected by the residue gas header 114 is used on-site for fuel. The residue gas is evacuated to a midstream pipeline. The residue gas is used for gas lift reinjection. The residue gas is treated in a gas sweetening unit to remove hydrogen sulfide and other contaminants. The residue gas is directed to a flare system as a safety measure for handling excess gas. The residue gas is used for on-site power generation using gas-fired generators or turbines. The system includes gas composition analyzers to monitor gas quality of the residue gas. The system includes flow meters to measure gas volumes of the residue gas. The system includes automated valves to control the routing of residue gas to different utilization options.

The chemical injection pump 106 and the injection header 109 introduce desalting and de-emulsification chemicals into the process. The chemical injection system includes multiple injection points for different types of chemicals for more precise control over desalting and de-emulsification processes. The chemical injection system incorporates inline mixing devices to ensure thorough blending of the chemicals with the wellhead fluid.

The cleaning header 108 is used to introduce acid washing solutions for removing certain types of scale or mineral deposits. The distillation system is refurbished on a periodic basis to remove salt, scale, and other fouling from the reboiler 103 and the distillation column 102. The refurbishment process uses chemical cleaning to address fouling. The refurbishment process uses high-pressure washing to address fouling. The refurbishment process uses mechanical scrubbing to address fouling.

The water treatment unit 111 uses filtration to reduce total dissolved solids in the produced water. The water treatment unit 111 uses reverse osmosis to reduce total dissolved solids in the produced water. The water treatment unit 111 uses chemical treatment to remove dissolved minerals and other impurities from the water. The water treatment unit 111 uses membrane filtration to further reduce total dissolved solids in the produced water. The water treatment unit 111 uses electrocoagulation to further reduce total dissolved solids in the produced water. The treated water with reduced total dissolved solids is reinjected into the separator 101 as wash water. The wastewater is reinjected into the reservoir for stimulation purposes. The wastewater is injected into a Class II disposal well. The wastewater is transported off-site via trucks for treatment or disposal at specialized facilities. The system includes sensors to monitor water quality parameters of the wastewater. The system includes flow meters to measure water volumes of the wastewater. The system includes automated valves and pumps to control the routing of water within the system.

The system incorporates online analyzers to continuously monitor the salt content of the crude oil at various stages of the process. The system includes a salt recovery unit to process the concentrated brine and recover valuable minerals as a byproduct. The system includes heat integration between hot and cold streams to reduce external energy requirements for heating and cooling.

The programmable logic controller 200 detects accumulation of salts, scale or other fouling in the system and triggers recycling of hot oil in the system. The programmable logic controller 200 detects that the distillation system efficiency has gone down and issues a message to the operator recommending external hot oil wash. The programmable logic controller 200 sends notification to the operator that external hot oil wash is recommended based on the configurable timer 204. The programmable logic controller 200 sends notification to the operator that a comprehensive refurbish is recommended based on the configurable timer 204 or if performance degrades below a certain configurable threshold. The programmable logic controller 200 uses machine learning to aid in determining when sensor input indicates that a condition exists where remedial action is to be taken. The programmable logic controller 200 detects increased pressure drop across the distillation column 102 as indicative of blockage caused by salt accumulation and scaling. The programmable logic controller 200 monitors power consumption of the heating element 116 and temperature in the reboiler 103 to determine that power requirement has increased indicating salt and scale accumulation on the heating element 116. Chemical sensors monitor the composition of the outgoing stabilized hydrocarbon stream to allow the programmable logic controller 200 to detect a salt content over a specified threshold.

Communication between the programmable logic controller 200 and sensors or controlled devices is wired. Communication between the programmable logic controller 200 and sensors or controlled devices is wireless. The operator interface 202 is provided at least in part by appropriate software running on a mobile computing device used by the operator.

Flow between various components is controlled by valves alone using gravity and pressure to motivate the flow instead of pumps.

The system can further be described as a desalting system of the current disclosure for processing a hydrocarbon fluid comprising hydrocarbons, water, and dissolved salts, the system comprising:

• • a. a separation vessel configured to receive the hydrocarbon fluid and separate the hydrocarbon fluid into a liquid hydrocarbon stream and a wastewater stream;
  • b. a distillation column having a lower region, the distillation column configured to receive the liquid hydrocarbon stream from the separation vessel;
  • c. a reboiler in fluid communication with the distillation column, wherein the lower region of the distillation column is positioned vertically below the reboiler such that saline water preferentially accumulates in the lower region of the distillation column and is inhibited from accumulating within the reboiler;
  • d. one or more evacuation ports configured to remove accumulated saline water from the lower region of the distillation column;
  • e. one or more cleaning ports configured to introduce at least one of heated fluid, steam, or chemical descaling agents into at least one of the distillation column or the reboiler; and
  • f. at least one cleaning mechanism associated with the reboiler selected from:
    • i. a removable heating element configured for extraction from the reboiler to permit mechanical cleaning,
    • ii. a mechanical cleaning device configured to remove scale from internal surfaces of the reboiler, or
    • iii. an ultrasonic cleaning device configured to transmit ultrasonic energy into fluid or surfaces within the reboiler to dislodge salt or scale deposits.

The desalting system of the current disclosure, wherein the removable heating element is extractable through a flange opening in the reboiler.

The desalting system of the current disclosure, wherein the flange opening provides access to the removable heating element without requiring disassembly of the reboiler vessel.

The desalting system of the current disclosure, wherein the mechanical cleaning device comprises at least one of a scraping element, a brushing element, a pigging element, or an abrasive element configured to contact internal surfaces of the reboiler.

The desalting system of the current disclosure, wherein the ultrasonic cleaning device comprises one or more ultrasonic transducers mounted externally on a wall of the reboiler.

The desalting system of the current disclosure, wherein the one or more ultrasonic transducers are configured to operate while hydrocarbon processing continues within the reboiler.

The desalting system of the current disclosure, wherein the one or more cleaning ports are configured to selectively introduce at least one of hot oil, steam, acid washing solution, or chemical descaling solution into at least one of the distillation column or the reboiler.

The desalting system of the current disclosure, further comprising a controller configured to initiate one or more cleaning operations in response to detection of salt accumulation within at least one of the distillation column or the reboiler.

The desalting system of the current disclosure, wherein the controller is configured to detect salt accumulation based on at least one of an increased pressure drop across the distillation column or an increased power consumption of a heating element within the reboiler.

The desalting system of the current disclosure, further comprising a special coating on at least one of the reboiler, the distillation column, or associated piping, wherein the special coating is configured to prevent nucleation of salt deposits.

The desalting system of the current disclosure, wherein the special coating has at least one of a smooth non-porous surface, low surface energy, or non-stick properties.

A method for desalting a hydrocarbon fluid of the current disclosure, comprising:

• • a. introducing the hydrocarbon fluid into a separation vessel;
  • b. separating the hydrocarbon fluid into a liquid hydrocarbon stream and a wastewater stream within the separation vessel;
  • c. directing the liquid hydrocarbon stream to a distillation column;
  • d. positioning a reboiler in fluid communication with the distillation column such that saline water accumulates in a lower region of the distillation column rather than within the reboiler;
  • e. removing accumulated saline water from the lower region of the distillation column; and
  • f. performing at least one cleaning operation on the reboiler selected from:
    • i. circulating heated hydrocarbon fluid through the reboiler,
    • ii. introducing steam or chemical descaling agents into the reboiler,
    • iii. mechanically cleaning internal surfaces of the reboiler,
    • iv. removing a heating element from the reboiler for mechanical cleaning or replacement, or
    • v. applying ultrasonic energy to the reboiler to dislodge salt or scale deposits.

The method of the current disclosure, wherein mechanically cleaning internal surfaces of the reboiler comprises inserting a cleaning tool into the reboiler through a flange opening without fully disassembling the reboiler.

The method of the current disclosure, wherein applying ultrasonic energy to the reboiler comprises transmitting ultrasonic energy at a frequency effective to disrupt salt crystal adhesion to internal reboiler surfaces.

The method of the current disclosure, wherein applying ultrasonic energy to the reboiler occurs while hydrocarbon processing continues within the reboiler.

The method of the current disclosure, further comprising detecting accumulation of salt or scale within the reboiler based on at least one of an increased pressure drop across the distillation column or an increased power consumption of a heating element within the reboiler, and initiating the at least one cleaning operation in response to the detecting.

The method of the current disclosure, further comprising injecting desalting and de-emulsion additives into at least one of the separation vessel, the distillation column, or the reboiler to facilitate separation of dissolved salts into a water phase.

A desalting system for processing wellhead fluid of the current disclosure, the system comprising:

• • a. a separator configured to separate the wellhead fluid into wastewater, liquid hydrocarbons, and gaseous hydrocarbons;
  • b. a distillation column connected to the separator and configured to receive the liquid hydrocarbons;
  • c. a reboiler connected to the distillation column and comprising a heating element;
  • d. a programmable logic controller configured to monitor operating parameters of the desalting system and detect accumulation of at least one of salts, scale, or fouling within the desalting system; and
  • e. a cleaning system configured to introduce at least one of heated fluid, steam, or chemical descaling agents into at least one of the distillation column or the reboiler in response to detection of accumulation by the programmable logic controller.

The desalting system of the current disclosure, wherein the programmable logic controller is configured to detect accumulation based on at least one of an increased pressure drop across the distillation column or an increased power consumption of the heating element.

The desalting system of the current disclosure, wherein the programmable logic controller is further configured to send a notification to an operator interface recommending at least one of an external hot oil wash or a comprehensive refurbishment based on at least one of a configurable timer or performance degradation below a configurable threshold.

Referring now to the drawings FIG. 1-3, and more particularly to FIG. 1, there is shown, a processing system is shown for processing wellhead fluid 100. FIG. 1 illustrates a schematic diagram of an oilfield fluid processing system. It shows various components connected by pipelines (which may be connected by flanges, shown as parallel lines forming a break in FIG. 1), starting from an oil well 100. The system shown in this example includes a separator 101, a distillation column 102, and a reboiler 103, each having a weir (101b, 102b, and 103b illustrated in FIG. 1 as vertical dashed lines). There are several numbered components and flow paths, including valves (107, 118-124), pumps (104, 105, 106, 117), and input/output streams (108, 109, 110, 112, 113, 114, 115). The distillation column (102) is depicted as a tall vessel with internal structures. The reboiler 103 is shown as a horizontal vessel with a heating element 116. A programmable logic controller PLC 200 is indicated in the top right corner. While most connections are not illustrated in FIG. 1 for clarity, the PLC 200 may be in electrical signal communication with various sensors (including illustrated interface level sensors (101a, 102a, 103a) and non-illustrated sensors such as pressure sensors, temperature sensors, chemical composition sensors, etc.), as well as in electrical signal communication with devices to be controlled, which may include some or all of the valves (107, 118-124), pumps (104, 105, 106, 117), and the heating element 116.

Additional devices could be controlled, such as a device for applying an electrical field across the liquid contained in the separator 101 or other component. Such communication could be wired and/or wireless. The drawing also shows various interconnections between the components, suggesting a complex fluid processing and control system for treating wellhead fluids. The example shown in FIG. 1 is representative of various system configurations to illustrate various components, and should not be interpreted as limiting. For example, where flow between various components is shown as being controlled by a pump (typically in combination with one or more valves, not shown), such flow could be controlled by valves alone using gravity and/or pressure to motivate the flow. Similarly, where connections between components are shown without pumps (indicating flow by gravity and/or pressure), pumps could be included if necessary to motivate flow for a particular configuration.

Furthering the description of FIG. 1 the system may receive the wellhead fluid 100 as input, which typically contains a mixture of hydrocarbons, water, and various impurities such as salts and minerals.

The wellhead fluid 100 may first undergo pressure regulation or reduction by a pressure regulating valve 107 to regulate the system inlet flow. This pressure reduction step may help prepare the fluid for subsequent processing stages.

After pressure reduction, the well fluid 100 may enter a separator 101, which may be a component of a stabilization system or a separate component of an overall processing system. The separator 101 may be designed to perform an initial separation of the wellhead fluid 100 into different streams, which may include wastewater/brine, liquid hydrocarbons 110, and gaseous hydrocarbons which may be collected by a residue gas header 114.

The pressure-stabilized stream enters the inlet 3-phase separator 101 where an interface level transmitter 101a monitors the oil-water interface level. The discrete hydrocarbon stream spills over a weir 101b and exits the separator 101 as indicated by stream 110.

Interface level transmitters 102a and 103a may also be used to monitor water build up respectively in the distillation column 102 and reboiler 103, behind weirs 102b and 103b.

In one embodiment the built-up water from the distillation column 102 and reboiler 103 may be reinjected into the beginning of the process 101 via pump 105. This water, typically containing brine, may be removed as is (as indicated by stream 112) or may be desalted (such as by water treatment unit 111) and the reduced salt water either removed (as indicated by stream 113) or returned to separator 101.

In one embodiment the feed separator 101 uses an electric charge to increase water separation from the oil.

In one embodiment chemical injection via pump 106 and header 109 is used to increase water separation from the oil.

In one embodiment the feed separator 101 uses a coalescing media to increase water separation from the oil.

The gaseous hydrocarbon stream leaving the separator 101 is fed to a common residue gas manifold 114.

In one embodiment the separator 101 is back pressure controlled.

Produced water is removed from the inlet separator 101 for disposal 112.

The hydrocarbon liquid stream 110 exiting the inlet separator 101 is fed to a distillation column 102.

In one embodiment the distillation column 102 is randomly packed.

In another embodiment the distillation column 102 is trayed.

Liquids leaving the distillation column 102 are fed to a 3 phase reboiler 103.

Vapor leaving the reboiler 103 is returned to the distillation column 102.

Stabilized desalted crude leaves the reboiler to an on-spec product manifold 105 for distribution.

In one embodiment the stabilized desalted crude is cooled before the product manifold 105.

The gaseous hydrocarbons leaving the distillation column 102 are fed to a common residue gas manifold 114.

In one embodiment the residue gas 114 is used on-site for fuel.

In another embodiment the residue gas 114 is evacuated to a midstream pipeline.

In yet another embodiment the residue gas 114 is used for gas lift reinjection.

In another embodiment header 108 is added to enable steam or hot oil cleanup of the separator 101, distillation column 102, and reboiler 103.

In another embodiment, the distillation system is built to enable the hot crude oil and/or hot salt water to circulate inside the system via pump 104.

In another embodiment, a special coating is used on various components including the heating element of the reboiler 116, the surface of the reboiler vessel 103, distillation column 102, and/or in the pipes to prevent nucleation of salt deposits or to enable easy cleanout.

In yet another embodiment, the distillation system is refurbished on a periodic basis to remove salt, scale, and other fouling from the reboiler and the column.

In one embodiment, sensors in the distillation system detect accumulation of salty water in the column 102 or the reboiler 103 and through an automated or manual control, causes one or more valves (118-124) to open and one or more pumps (104, 117) to turn on and evacuate the salty water from the column or reboiler. Such heated salty water could be recirculated to the separator 101.

In one embodiment, the programmable logic controller (PLC 200) of the distillation system detects accumulation of salts, scale or other fouling in the system and triggers recycling of hot oil in the system.

In one embodiment, the programmable logic controller (PLC 200) of the distillation system detects that the distillation system efficiency has gone down and that external steam or hot oil clean out is required. The PLC than issues a message to the operator of the distillation system recommending external hot oil wash.

In one embodiment, the programmable logic controller (PLC 200) of the distillation system sends notification to the operator that external hot oil wash is recommended based on a configurable timer.

In one embodiment, the programmable logic controller (PLC 200) of the distillation system sends notification to the operator that a comprehensive refurbish is recommended based on a configurable timer or if performance degrades below a certain configurable threshold.

In some embodiments, some or all the aforementioned desalting steps may be built into the distillation system.

As shown in FIG. 1, the liquid hydrocarbon stream 110 may be directed to a distillation column 102 that is a component of the stabilization system, designed to further separate the hydrocarbons based on their boiling points.

Connected to the distillation column 102, the stabilization system may include a reboiler 103 having a heating element 116. The reboiler 103 may provide heat to the bottom of the distillation column 102 (such as by introducing heated liquid and/or gas hydrocarbons into the distillation column 102), facilitating the separation process by vaporizing the more volatile components for removal via the residue gas header 114.

As the fluids flow through the system under the control of devices such as valves and/or pumps (all or some of which may be under the control of PLC 200), they may undergo various separation and stabilization processes. The primary outputs of the system may include stabilized crude oil 115, having reduced salt content compared to the input wellhead fluid 110, and gaseous hydrocarbons removed from distillation column 102 (and optionally from separator 101) via the residue gas header 114.

In some cases, the wastewater separated in the initial stages may be further processed or disposed of separately, and could be processed for recovery of the brine for liquid reinjection. In each of the main components (101, 102, 103), denser wastewater may separate from lighter liquid hydrocarbons and collect behind weirs (101b, 102b, 103b) while the lighter liquid hydrocarbons flow over the weirs (101b, 102b, 103b). The gaseous hydrocarbons produced by the system may be collected and potentially used for various purposes, such as on-site power generation, fuel, or reinjection.

This basic configuration of the stabilization system may provide a foundation for more advanced desalting and descaling processes, which may be incorporated to enhance the system's efficiency and effectiveness in producing desalted crude oil.

In some cases, the stabilization system may incorporate enhanced desalting and de-emulsification features to improve the separation of water and impurities from the oil. These features may include chemical injection, coalescing media, and/or electric charge application.

The stabilization system may include a chemical injection pump 106 and an injection header 109 for introducing desalting and de-emulsification chemicals into the process. These chemicals may be added to the wellhead fluid 100 before it enters the feed separator 101 or at various points within the stabilization system, such as distillation column 102 and/or reboiler 103. The injection of these chemicals may help break down emulsions and facilitate the separation of water and oil.

In some cases, the feed separator 101 may utilize a coalescing media to increase water separation from the oil. The coalescing media may provide a large surface area for small water droplets to combine and form larger droplets, which are easier to separate from the oil phase. This coalescing process may enhance the overall efficiency of the water-oil separation in the feed separator 101.

The feed separator 101 may also employ an electric charge to further increase water separation from the oil. An electric field may be applied across the separator 101 by an electrical device (which may be controlled under the direction of PLC 200), which may cause water droplets to coalesce more rapidly. This electrostatic coalescence process may be particularly effective for breaking down stable emulsions and separating fine water droplets that might otherwise remain dispersed in the oil phase.

The use of chemical injection, coalescing media, and electric charge application (either alone or in combination) within the system components may significantly improve the desalting and de-emulsification performance of the stabilization system. These enhanced features may result in more efficient separation of water and impurities from the oil, potentially leading to higher quality stabilized crude oil output and reduced scaling and fouling issues in downstream equipment.

In some cases, the stabilization system may incorporate features for hot oil recycling and external cleaning to enhance system performance and reduce downtime due to fouling and scaling. These features may include a recycling system, a pump for hot oil recycling, and a cleaning header 108 for external hot oil, acid washing, or steam cleanout.

The stabilization system may include a recycling system that allows for the circulation of hot oil within the system. This hot oil recycling capability may help prevent the buildup of salts, scale, and other fouling materials on the internal surfaces of the system components. By maintaining a continuous flow of hot oil, the system may reduce the likelihood of deposits forming and adhering to critical surfaces.

A dedicated pump may be included in the stabilization system to facilitate the hot oil recycling process. This pump may be designed to circulate hot oil through various components of the system, including the separator, distillation column, and reboiler. The circulation of hot oil may help maintain optimal operating temperatures throughout the system while also providing a cleaning effect.

In some cases, the stabilization system may include a cleaning header 108 to enable external cleaning processes. This cleaning header 108 may be designed to allow for the introduction of steam, hot oil, or acid washing solutions into the system, possibly under control of the PLC 200. The ability to perform external cleaning may be particularly useful for addressing more severe fouling or scaling issues that cannot be adequately addressed through the internal hot oil recycling process alone.

The cleaning header 108 may be configured to allow for the introduction of steam for steam cleaning. Steam cleaning may be effective in removing certain types of deposits and may also help in maintaining system temperatures during the cleaning process.

In some cases, the cleaning header 108 may be used to introduce hot oil from an external source for more intensive cleaning. This external hot oil cleaning process may be particularly useful for addressing heavy fouling or for periodic maintenance of the system.

The cleaning header 108 may also allow for the introduction of acid washing solutions. Acid washing may be effective in removing certain types of scale or mineral deposits that may accumulate in the system over time.

By incorporating these hot oil recycling and external cleaning capabilities, the stabilization system may achieve improved operational efficiency and reduced downtime for maintenance. The ability to perform regular internal cleaning through hot oil recycling, combined with the option for more intensive external cleaning when necessary, may help extend the lifespan of system components and maintain optimal performance over time.

In some cases, the stabilization system may incorporate sensors and a programmable logic controller (PLC) 200 for monitoring and controlling the desalting and descaling processes. These sensors may be designed to detect various conditions within the system, such as salt accumulation, water buildup, and overall system efficiency. In some cases, changes in process parameters detected by sensors can be interpreted by the PLC 200 as indicative of a problem in a particular portion of the system if the parameters exceed a set threshold or otherwise match a pattern indicative of a problem. For example, an increased pressure drop across the distillation column 102 may be indicative of blockage caused by salt accumulation and/or scaling, and the PLC 200 may direct controlled devices of the system 100 to take remedial action, such as directing introduction of a desalting chemical (such as via chemical injection system 106 & 109), directing cleaning agents (steam, hot oil, etc.) via cleaning header 108, and/or recirculating hot oil from reboiler 103. In another example, sensors monitoring the power consumption of heating element 116 and the temperature in reboiler 103 may provide data to the PLC 200 that allow the PLC 200 to determine that the power requirement of heating element 116 to maintain a specified temperature in reboiler 103 has increased. This could be interpreted as indicating salt and/or scale accumulation on the heating element 116, and the PLC 200 could direct an appropriate action of trying to clean the heating element 116 and/or providing notice to an operator to service or replace the heating element 116. In yet another example, one or more chemical sensors could monitor the composition of the outgoing stabilized hydrocarbon stream 115 to allow PLC 200 to detect a salt content over a specified threshold, and PLC 200 could then take action to remedy the situation, such as increasing addition of chemicals to remove salt, directing a cleaning cycle, etc. The PLC 200 may use machine learning to aid in determining when sensor input indicates that a condition exists where remedial action should be taken.

The stabilization system may include sensors (such as interface level sensors 101a, 102a, and 103a) capable of detecting the accumulation of salty water in various components, such as the distillation column or the reboiler. When these sensors detect a buildup of salty water, the PLC 200 may automatically initiate a process to evacuate the salty water from the affected components. This automated evacuation process may help maintain optimal operating conditions and prevent potential issues related to excessive water accumulation.

In some cases, the PLC 200 may be configured to detect the accumulation of salts, scale, or other fouling materials within the stabilization system. Such detection may be based on sensors that monitor operating parameters, and the PLC 200 identifying a situation where one or more parameters (temperature, pressure, flow, fluid level, etc.) are outside specified boundaries, indicating that possible salt accumulation is interfering with the proper operation. Upon detecting such accumulation, the PLC 200 may automatically trigger a hot oil recycling process. This hot oil recycling may help remove or prevent the buildup of deposits on internal surfaces, potentially extending the time between required maintenance procedures.

The PLC 200 may also be programmed to monitor overall system efficiency. In some cases, the PLC 200 may use data from various sensors to assess the performance of the stabilization system, such as detecting that increased power to one or more components is required to maintain a steady condition, and/or that parameters in a particular component are changing unexpectedly. If the PLC 200 detects that the system efficiency has decreased below a certain configurable threshold, it may send a notification to the system operator. This notification may recommend specific maintenance actions, such as an external steam or hot oil cleanout.

FIG. 3 illustrates one example of the PLC 200 connected (either via wired connection or wireless communication) so as to receive data from several sensors, such as interface level sensors (101a, 102a, 103a), additional sensors (S1-Sn), and sensors associated with controlled devices such as pumps (104, 105, 117), chemical injection system 106, cleanout system 108, heating element 116, valves (107, 118-124, not all shown in FIG. 3), and any other devices (D1-Dn). In the case of controlled devices, the PLC 200 may not only receive sensor data (such as reports on the current operating status of the device) but also communicate control instructions to such devices to adjust their operation. The PLC 200 may also communicate with an operator interface 202 that presents information to an operator and allows the operator to provide input to the PLC 200. Such interface may, at least in part, be provided by appropriate software running on a mobile computing device used by the operator. In some cases, the PLC 200 may be configured with timers such as illustrated configurable timer 204 to trigger periodic maintenance notifications. For example, the PLC 200 may send a notification to the operator via operator interface 202 recommending an external hot oil wash based on the configurable timer 204. This timer-based approach may help ensure regular maintenance is performed even in the absence of detected performance issues. Controlled devices employed in the system 100 may include reboiler water/oil evacuation pump 104, separator water evacuation pump 105, chemical injection pump 106, pressure regulating valve 107, wastewater treatment device 111, reboiler heating element 116, distillation column water evacuation pump 117, Desalted crude flow/pressure control 118, Waste water/water recycle flow/pressure control 119, Chemical injection flow/pressure control 120, reboiler water evacuation valve 121, distillation column water evacuation valve 122, Residue gas flow/pressure control 123, and/or Column feed flow/pressure control 124.

The PLC 200 may also be programmed to recommend more comprehensive maintenance procedures. In some cases, the PLC 200 may send a notification to the operator suggesting a complete system refurbishment. This recommendation may be based on a configurable timer or triggered when the system performance degrades below a certain configurable threshold.

By incorporating these sensor-based monitoring and control features, the stabilization system may achieve more efficient and automated management of the desalting and descaling processes. This approach may help minimize downtime, optimize system performance, and extend the operational life of system components.

In some cases, the stabilization system may incorporate specialized coatings and maintenance features to enhance system performance and reduce fouling issues. These features may include special coatings applied to various components and design elements that facilitate easy maintenance and refurbishment.

The stabilization system may utilize special coatings on various components to prevent the nucleation of salt deposits or to enable easy cleanout. These coatings may be applied to critical surfaces within the system, such as the heating element of the reboiler, the surface of the reboiler vessel, the distillation column, and the pipes connecting different components.

The special coatings may be designed to have specific properties that inhibit the formation and adhesion of salt deposits. In some cases, the coatings may have a smooth, non-porous surface that reduces the likelihood of salt crystals nucleating and growing on the coated surfaces. The coatings may also have low surface energy, which may further discourage the adhesion of salt deposits.

In addition to preventing salt nucleation, the special coatings may be selected for their ability to facilitate easy cleanout of any deposits that do form. The coatings may have non-stick properties that allow salt deposits or other fouling materials to be more easily removed during cleaning processes. This feature may reduce the time and effort required for maintenance procedures and may help maintain optimal system performance over time.

The stabilization system may be designed to allow for periodic refurbishment to remove salt, scale, and other fouling from the reboiler and the distillation column. This design may include features that facilitate access to internal components for cleaning and maintenance.

In some cases, the reboiler may be equipped with a flange that enables the extraction of the heating element 116. This feature may allow maintenance personnel to easily remove the heating element 116 for thorough cleaning or replacement, without the need to disassemble the entire reboiler 103. The ability to extract the heating element 116 may be particularly useful for addressing fouling issues that may accumulate on the heating surfaces over time.

The stabilization system may be designed with maintenance schedules that include periodic refurbishment procedures. These procedures may involve a comprehensive cleaning of the system components, including the reboiler 103, distillation column 102, and associated piping such as headers 108, 109, and/or 114. The refurbishment process may use various cleaning methods, such as chemical cleaning, high-pressure washing, or mechanical scrubbing, depending on the nature and extent of the fouling.

By incorporating these specialized coatings and maintenance features, the stabilization system may achieve improved resistance to fouling and more efficient cleaning processes. These features may contribute to extended operational periods between maintenance shutdowns, reduced downtime for cleaning, and overall improved system performance and longevity.

In some cases, the stabilization system may incorporate features for managing and reusing wastewater produced during the wellhead fluid processing. This wastewater management approach may include processes for reducing total dissolved solids (TDS) in the produced water and options for reinjecting the treated water back into the system or disposing of it through various methods.

The stabilization system may include a water treatment unit (such as water treatment unit 111 illustrated) designed to reduce the total dissolved solids content of the produced water. This treatment process may involve various techniques such as filtration, reverse osmosis, or chemical treatment to remove dissolved minerals and other impurities from the water.

In some cases, the treated water with reduced Total Dissolved Solids (TDS) may be reinjected into the separator 101 as wash water. This reinjection process may help improve the efficiency of the initial separation stage by providing additional water for washing and diluting the incoming wellhead fluid 100. The use of treated water for this purpose may help reduce the overall water consumption of the system and minimize the need for fresh water inputs.

The stabilization system may offer multiple options for managing the produced wastewater. In some cases, the wastewater may be reinjected into the reservoir associated with oil well 100 for stimulation purposes. This reinjection process may help maintain reservoir pressure and potentially enhance oil recovery.

Another option for wastewater management may involve injecting the produced water into a Class II disposal well. Class II wells may be specifically designed for the disposal of fluids associated with oil and gas production. This disposal method may be used when reinjection into the production reservoir is not feasible or desirable.

In some cases, the wastewater may be transported off-site via trucks for treatment or disposal at specialized facilities. This option may be used when on-site treatment or disposal is not practical or when regulatory requirements necessitate off-site management of produced water. One embodiment is an oilfield distillation system that processes wellhead fluid to produce reduced salt stabilized crude, wastewater, and residue gas. The residue gas can be injected into a gathering pipeline, used onsite for power generation, used for gas lift, used as fuel, or sent to flare. The wastewater can be reinjected for stimulation purposes, or into a Class II well, or trucked off.

The stabilization system may include monitoring and control features to manage the wastewater treatment and reinjection processes. These features may include sensors to monitor water quality parameters, flow meters to measure water volumes, and automated valves and/or pumps to control the routing of water within the system.

In some cases, the stabilization system may incorporate features for managing and utilizing the residue gas produced during the wellhead fluid processing. The residue gas may be the gaseous hydrocarbons separated from the wellhead fluid during the stabilization process.

The stabilization system may offer multiple options for handling the residue gas. In some cases, the residue gas may be injected into a gathering pipeline. This option may allow for the efficient transportation of the gas to downstream processing facilities or markets. The injection into a gathering pipeline may require the residue gas to meet certain quality specifications, which may be achieved through the stabilization process.

In some cases, the residue gas may be used on-site for power generation. The stabilization system may include equipment for converting the residue gas into electrical power, such as gas-fired generators or turbines. This on-site power generation capability may help reduce the facility's reliance on external power sources and potentially lower operational costs.

The stabilization system may also provide the option to use the residue gas for gas lift operations. Gas lift may be a method of artificial lift that uses compressed gas to increase the flow rate of oil from a well. In this case, the residue gas may be compressed and reinjected into the well to assist in lifting the oil to the surface. This utilization of the residue gas may help enhance oil production and improve overall field efficiency.

In some cases, the stabilization system may include a flare system as a safety measure and for handling excess gas. Flaring may be used to safely dispose of gas that cannot be processed or utilized through other means. However, flaring may be considered a last resort option due to environmental considerations and potential loss of valuable resources.

The stabilization system may incorporate monitoring and control features to manage the routing and utilization of the residue gas. These features may include flow meters to measure gas volumes, gas composition analyzers to monitor gas quality, and automated valves to control the routing of gas to different utilization options.

By incorporating these gas management and utilization features, the stabilization system may achieve improved resource efficiency, potentially lower operational costs, and enhanced environmental performance in oil and gas production operations.

In some cases, the stabilization system may incorporate an integrated approach that combines multiple desalting and descaling features into a single, comprehensive distillation system. This integrated approach may optimize the overall process by addressing various aspects of salt removal and scale prevention throughout the system.

The integrated desalting system may incorporate chemical injection capabilities for introducing desalting and de-emulsion additives at strategic points in the process. These chemicals may be added before the distillation column or directly into the distillation system to enhance the separation of water and impurities from the oil.

In some cases, the integrated system may include features for hot steam or hot oil cleanup. Ports may be added to the distillation system to enable the introduction of hot steam or hot oil for periodic cleaning and maintenance. This capability may help prevent the buildup of salt deposits and other fouling materials on internal surfaces.

The integrated system may be designed to enable the circulation of hot crude oil within the system. This hot oil recycling feature may help maintain optimal operating temperatures and provide a continuous cleaning effect, potentially reducing the frequency of required maintenance shutdowns.

In some cases, the integrated desalting system may utilize special coatings on various components, including the heating element of the reboiler, the surface of the reboiler vessel, the distillation column, and associated piping. These coatings may be designed to prevent the nucleation of salt deposits or to facilitate easy cleanout during maintenance procedures.

The integrated system may incorporate sensors and automated control features to detect and manage the accumulation of salty water, salts, scale, or other fouling materials.

These sensors may work in conjunction with a programmable logic controller (PLC) to automate various processes, such as evacuating salty water or triggering hot oil recycling when necessary.

In some cases, the integrated desalting system may include features for periodic refurbishment to remove accumulated salt, scale, and other fouling materials from the reboiler and the distillation column. The system may be designed with easily accessible components to facilitate thorough cleaning and maintenance procedures.

The integrated approach may also incorporate wastewater management features, such as the ability to treat and reinject produced water as wash water or for other purposes within the system.

The integrated desalting system may also offer enhanced flexibility in managing various types of wellhead fluids. By incorporating multiple desalting and descaling techniques, the system may be better equipped to handle variations in fluid composition and impurity levels that may occur over time or between different wells.

In some cases, the integrated stabilization system may operate as a comprehensive unit to process wellhead fluid and produce desalted crude oil. The operation of the integrated system may involve multiple stages and processes, all of which may be coordinated by a programmable logic controller (PLC) to optimize performance and efficiency.

One such process 300 is shown in FIG. 2. The process 300 may begin with the reception 302 of wellhead fluid, which may contain a mixture of hydrocarbons, water, and various impurities such as salts and minerals. The wellhead fluid may first undergo pressure reduction to regulate the system inlet flow. This pressure reduction step may help prepare the fluid for subsequent processing stages.

After pressure reduction, the fluid may enter a separator. The separator may perform an initial separation 304 of the wellhead fluid into different streams, which may include wastewater, liquid hydrocarbons, and gaseous hydrocarbons. The PLC may monitor and control the separation process, adjusting parameters such as heat, pressure, electrical field, addition of chemicals, etc. as needed to maintain optimal separation efficiency.

In some cases, the PLC may activate chemical injection pumps to introduce 310 desalting and de-emulsion additives into the process. These chemicals may be added before the fluid enters the separator or at various points within the system to enhance the separation of water and impurities from the oil.

The liquid hydrocarbon stream from the separator may be directed 306 to a stabilization system for processing 308 to separate the hydrocarbon stream into stabilized crude oil and gaseous hydrocarbons. The stabilization system may employ a distillation column to further separate 312 the hydrocarbons based on their boiling points. The PLC may control valves, pumps, heating elements, and similar controlled device components to adjust the temperature and pressure within the distillation column to achieve the desired separation.

Connected to the distillation column, the system may include a reboiler. The reboiler may provide heat to the bottom of the distillation column, facilitating the separation process by vaporizing 314 the more volatile components. The PLC may regulate the heat input to the reboiler to maintain optimal distillation conditions.

As the fluids flow through the system, they may undergo various separation and stabilization processes 304, 312 and 314. The PLC may continuously monitor parameters such as temperature, pressure, and flow rates throughout the system via appropriate sensors monitoring such operating parameters, making adjustments as necessary to maintain optimal performance.

In some cases, the PLC may detect 316 the accumulation of salty water in the distillation column or reboiler. When this occurs, the PLC may automatically initiate a process to evacuate 318 the salty water from the affected components. This may involve opening specific valves and activating pumps to remove the salty water while minimizing disruption to the overall process.

The PLC may also monitor 320 for signs of salt, scale, or other fouling accumulation within the system. If such accumulation is detected 322, the PLC may trigger a remedial action 324 such as a hot oil recycling process. This may involve activating a dedicated pump to circulate hot oil through various components of the system, helping to prevent or remove deposits on internal surfaces. Alternative remedial actions, such as initiating a steam cleaning, etc., could be performed under step 324

In some cases, the PLC may determine that the system efficiency has decreased below a certain threshold. When this occurs, the PLC may send a notification to the system operator recommending specific maintenance actions, such as an external steam or hot oil cleanout.

Throughout the operation, the PLC may manage the routing and utilization of the residue gas produced during the process. This may involve directing the gas to a gathering pipeline, on-site power generation equipment, or gas lift operations, depending on the specific configuration and needs of the facility.

The PLC may also oversee the management of produced wastewater. This may include controlling the treatment process to reduce total dissolved solids and managing the reinjection of treated water as wash water or for other purposes within the system.

In some cases, the integrated system may incorporate periodic maintenance procedures as part of its operation. The PLC may trigger these procedures based on configurable timers or performance thresholds. These maintenance activities may include hot oil washes, steam cleanouts, or more comprehensive refurbishment processes.

By coordinating these various processes and components, the integrated stabilization system may achieve efficient and continuous operation, producing desalted crude oil while minimizing scaling, salt depositions, and downtime for descaling.

In some cases, the stabilization system may incorporate various alternative configurations and variations to accommodate different operational requirements or to optimize performance under specific conditions.

The distillation column in the stabilization system may be designed with different internal structures to enhance separation efficiency. In some cases, the distillation column may be randomly packed with materials such as ceramic rings, metal saddles, or structured packing. These random packing materials may provide a large surface area for vapor-liquid contact, potentially improving the separation of components in the wellhead fluid.

Alternatively, the distillation column may be equipped with trays. In some cases, the trayed column may use bubble cap trays, sieve trays, or valve trays. Each tray type may offer specific advantages in terms of efficiency, pressure drop, or fouling resistance, allowing the system to be tailored to the particular characteristics of the wellhead fluid being processed.

The stabilization system may incorporate various methods for enhancing water separation from the oil phase. In some cases, electrostatic coalescers may be used in addition to or instead of chemical demulsifiers. These electrostatic devices may apply an electric field to the fluid, promoting the coalescence of water droplets and facilitating their separation from the oil.

In some cases, the stabilization system may employ centrifugal separators or hydrocyclones to enhance the separation of water and oil. These devices may use centrifugal force to separate fluids of different densities, potentially improving the efficiency of the desalting process.

The stabilization system may offer additional options for gas management beyond those previously described. In some cases, the system may include a gas sweetening unit to remove hydrogen sulfide and other contaminants from the residue gas. This may allow the gas to meet more stringent quality requirements for pipeline injection or other uses.

Wastewater management in the stabilization system may also incorporate alternative approaches. In some cases, the system may include advanced water treatment technologies such as membrane filtration or electrocoagulation to further reduce total dissolved solids in the produced water. These advanced treatment methods may allow for more extensive reuse of the water within the production process or enable its use for other purposes.

The stabilization system may incorporate variations in the cooling process for the stabilized desalted crude oil. In some cases, the system may include a heat exchanger to cool the stabilized crude before it reaches the product manifold. This cooling step may help reduce the vapor pressure of the crude oil, potentially making it safer for storage and transportation.

The cooling process may also help prevent the loss of lighter hydrocarbons that might otherwise vaporize at higher temperatures.

In some cases, the cooling of the stabilized desalted crude may be achieved through the use of air coolers instead of or in addition to liquid-based heat exchangers. Air cooling may be particularly advantageous in locations where water for cooling is scarce or expensive.

The stabilization system may also incorporate variations in the reboiler design. In some cases, the system may use a kettle-type reboiler instead of a traditional shell-and-tube design. Kettle reboilers may offer advantages in terms of fouling resistance and ease of maintenance, which may be beneficial when processing wellhead fluids with high scaling potential.

In some cases, the stabilization system may incorporate alternative heating methods for the reboiler. For example, the system may use direct-fired heaters or electric heating elements instead of steam heating. These alternative heating methods may offer advantages in terms of control precision or may be more suitable for locations where steam generation is not practical.

The stabilization system may also include variations in the separator design. In some cases, the system may use a horizontal separator instead of a vertical one, which may be advantageous for handling fluids with high gas-to-liquid ratios or for installations with height restrictions.

In some cases, the stabilization system may incorporate additional stages of separation. For example, the system may include a pre-flash drum before the main separator to remove the lightest components of the wellhead fluid. This additional separation stage may help reduce the load on the main separator and distillation column, potentially improving overall system efficiency.

The stabilization system may also offer variations in the chemical injection system. In some cases, the system may include multiple injection points for different types of chemicals, allowing for more precise control over the desalting and de-emulsification processes. The system may also incorporate inline mixing devices to ensure thorough blending of the chemicals with the wellhead fluid.

In some cases, the stabilization system may include additional monitoring and control features. For example, the system may incorporate online analyzers to continuously monitor the salt content of the crude oil at various stages of the process. This real-time monitoring may allow for more responsive adjustments to the desalting process, potentially improving the quality of the final product.

The stabilization system may also offer variations in the handling of recovered salts and other impurities. In some cases, the system may include a salt recovery unit to process the concentrated brine and recover valuable minerals. This recovered material may be sold as a byproduct, potentially offsetting some of the operational costs of the desalting process.

In some cases, the stabilization system may incorporate energy recovery features to improve overall efficiency. For example, the system may include heat integration between hot and cold streams, potentially reducing the external energy requirements for heating and cooling.

A process for producing desalted crude oil from wellhead fluid may comprise the steps of:

• • a receiving wellhead fluid;
  • b separating the wellhead fluid into wastewater, liquid hydrocarbons, and gaseous hydrocarbons;
  • c directing the liquid hydrocarbons to a stabilization system comprising a
  • d distillation column and a reboiler; and outputting stabilized crude oil and gaseous hydrocarbons from the stabilization system, wherein the stabilization system is controlled by a programmable logic controller (PLC) to minimize scaling and salt deposition.

The process may further comprise injecting a chemical mix of desalting and de-emulsion additives into the stabilization system.

The stabilization system used in the process may comprise ports for enabling hot steam or hot oil cleanup.

The stabilization system used in the process may be configured to enable hot crude oil to circulate inside the system.

The stabilization system used in the process may comprise a special coating on at least one of the reboiler, distillation column, or associated piping to prevent nucleation of salt deposits.

The process may further comprise detecting accumulation of salty water in the distillation column or reboiler using sensors, and automatically evacuating the salty water through valves controlled by the PLC.

The PLC used by the process may be configured to detect accumulation of salts, scale, or other fouling in the stabilization system and trigger recycling of hot oil in the system.

A stabilization system for producing desalted crude oil from wellhead fluid may comprise:

• • a. a separator configured to separate wellhead fluid into wastewater, liquid hydrocarbons, and gaseous hydrocarbons;
  • b. a distillation column connected to the separator and configured to receive the liquid hydrocarbons;
  • c. a reboiler connected to the distillation column; and
  • d. a programmable logic controller (PLC) configured to control the stabilization system to minimize scaling and salt deposition.

The stabilization system may further comprise an injection system configured to inject a chemical mix of desalting and de-emulsion additives into the stabilization system.

The stabilization system may further comprise ports configured to enable hot steam or hot oil cleanup of the distillation column and reboiler.

The stabilization system may further comprise a recycling system configured to enable hot crude oil to circulate inside the stabilization system.

The stabilization system may have at least one of the reboiler, distillation column, or associated piping comprising a special coating configured to prevent nucleation of salt deposits.

The stabilization system may further comprise sensors configured to detect accumulation of salty water in the distillation column or reboiler, wherein the PLC is configured to automatically evacuate the salty water through valves controlled by the PLC based on data from the sensors.

The PLC may be configured to detect accumulation of salts, scale, or other fouling in the stabilization system and trigger recycling of hot oil in the system.

A method for managing residue gas produced during wellhead fluid processing may comprise the steps of:

• • a. separating wellhead fluid into wastewater, liquid hydrocarbons, and gaseous hydrocarbons;
  • b. processing the liquid hydrocarbons in a stabilization system to produce stabilized crude oil and residue gas; and
  • c. directing the residue gas to at least one of: a gathering pipeline, on-site power generation equipment, or gas lift operations.
  • d. The method may further comprise treating the residue gas to remove hydrogen sulfide and other contaminants before directing the residue gas to the gathering pipeline.

Where the method comprises directing the residue gas to on-site power generation equipment, it may comprise using the residue gas to fuel gas-fired generators and/or turbines for producing electrical power.

Where the method comprises directing the residue gas to gas lift operations, may comprise compressing the residue gas and reinjecting it into a well to assist in lifting oil to the surface.

The method may further comprise monitoring the composition and flow rate of the residue gas using gas analyzers and flow meters.

The method may comprise monitoring to automatically adjust the routing of the residue gas between the gathering pipeline, on-site power generation equipment, and gas lift operations based on predetermined criteria.

In some embodiments the method or methods described above may be executed or carried out by a computing system including a tangible computer-readable storage medium, also described herein as a storage machine, that holds machine-readable instructions executable by a logic machine (i.e., a processor or programmable control device) to provide, implement, perform, and/or enact the above described methods, processes and/or tasks. When such methods and processes are implemented, the state of the storage machine may be changed to hold different data. For example, the storage machine may include memory devices such as various hard disk drives, CD, or DVD devices. The logic machine may execute machine-readable instructions via one or more physical information and/or logic processing devices. For example, the logic machine may be configured to execute instructions to perform tasks for a computer program. The logic machine may include one or more processors to execute the machine-readable instructions. The computing system may include a display subsystem to display a graphical user interface (GUI) or any visual element of the methods or processes described above. For example, the display subsystem, storage machine, and logic machine may be integrated such that the above method may be executed while visual elements of the disclosed system and/or method are displayed on a display screen for user consumption. The computing system may include an input subsystem that receives user input. The input subsystem may be configured to connect to and receive input from devices such as a mouse, keyboard or gaming controller. For example, a user input may indicate a request that certain task is to be executed by the computing system, such as requesting the computing system to display any of the above described information, or requesting that the user input updates or modifies existing stored information for processing. A communication subsystem may allow the methods described above to be executed or provided over a computer network. For example, the communication subsystem may be configured to enable the computing system to communicate with a plurality of personal computing devices. The communication subsystem may include wired and/or wireless communication devices to facilitate networked communication. The described methods or processes may be executed, provided, or implemented for a user or one or more computing devices via a computer-program product such as via an application programming interface (API).

Since many modifications, variations, and changes in detail can be made to the described embodiments of the invention, it is intended that all matters in the foregoing description and shown in the accompanying drawings be interpreted as illustrative and not in a limiting sense. Furthermore, it is understood that any of the features presented in the embodiments may be integrated into any of the other embodiments unless explicitly stated otherwise. The scope of the invention should be determined by the appended claims and their legal equivalents.

In addition, the present invention has been described with reference to embodiments; it should be noted and understood that various modifications and variations can be crafted by those skilled in the art without departing from the scope and spirit of the invention. Accordingly, the foregoing disclosure should be interpreted as illustrative only and is not to be interpreted in a limiting sense. Further it is intended that any other embodiments of the present invention that result from any changes in application or method of use or operation, method of manufacture, shape, size, or materials which are not specified within the detailed written description or illustrations contained herein are considered within the scope of the present invention.

Insofar as the description above and the accompanying drawings disclose any additional subject matter that is not within the scope of the claims below, the inventions are not dedicated to the public and the right to file one or more applications to claim such additional inventions is reserved.

Although very narrow claims are presented herein, it should be recognized that the scope of this invention is much broader than presented by the claim. It is intended that broader claims will be submitted in an application that claims the benefit of priority from this application.

While this invention has been described with respect to at least one embodiment, the present invention can be further modified within the spirit and scope of this disclosure. This application is therefore intended to cover any variations, uses, or adaptations of the invention using its general principles. Further, this application is intended to cover such departures from the present disclosure as come within known or customary practice in the art to which this invention pertains and which fall within the limits of the appended claims.

Claims

1. A desalting system for processing a hydrocarbon fluid comprising hydrocarbons, water, and dissolved salts, the system comprising:

a separation vessel configured to receive the hydrocarbon fluid and separate the hydrocarbon fluid into a liquid hydrocarbon stream and a wastewater stream;

a distillation column having a lower region, the distillation column configured to receive the liquid hydrocarbon stream from the separation vessel;

a reboiler in fluid communication with the distillation column, wherein the lower region of the distillation column is positioned vertically below the reboiler such that saline water preferentially accumulates in the lower region of the distillation column and is inhibited from accumulating within the reboiler; and

one or more evacuation ports configured to remove accumulated saline water from the lower region of the distillation column.

2. The desalting system of claim 1, wherein one or more cleaning ports configured to introduce at least one of heated fluid, steam, or chemical descaling agents into at least one of the distillation column or the reboiler.

3. The desalting system of claim 1, wherein at least one cleaning mechanism associated with the reboiler selected from:

a removable heating element configured for extraction from the reboiler to permit mechanical cleaning,

a mechanical cleaning device configured to remove scale from internal surfaces of the reboiler, or

an ultrasonic cleaning device configured to transmit ultrasonic energy into fluid or surfaces within the reboiler to dislodge salt or scale deposits.

4. The desalting system of claim 3, wherein the mechanical cleaning device comprises at least one of a scraping element, a brushing element, a pigging element, or an abrasive element configured to contact internal surfaces of the reboiler.

5. The desalting system of claim 3, wherein the ultrasonic cleaning device comprises one or more ultrasonic transducers mounted externally on a wall of the reboiler.

6. The desalting system of claim 5, wherein the one or more ultrasonic transducers are configured to operate while hydrocarbon processing continues within the reboiler.

7. The desalting system of claim 2, wherein the one or more cleaning ports are configured to selectively introduce at least one of hot oil, steam, acid washing solution, or chemical descaling solution into at least one of the distillation column or the reboiler.

8. The desalting system of claim 1, further comprising a controller configured to initiate one or more cleaning operations in response to detection of salt accumulation within at least one of the distillation column or the reboiler.

9. The desalting system of claim 8, wherein the controller is configured to detect salt accumulation based on at least one of an increased pressure drop across the distillation column or an increased power consumption of a heating element within the reboiler.

10. The desalting system of claim 1, further comprising a special coating on at least one of the reboiler, the distillation column, or associated piping, wherein the special coating is configured to prevent nucleation of salt deposits.

11. The desalting system of claim 10, wherein the special coating has at least one of a smooth non-porous surface, low surface energy, or non-stick properties.

12. A method for desalting a hydrocarbon fluid, comprising:

introducing the hydrocarbon fluid into a separation vessel;

separating the hydrocarbon fluid into a liquid hydrocarbon stream and a wastewater stream within the separation vessel;

directing the liquid hydrocarbon stream to a distillation column;

positioning a reboiler in fluid communication with the distillation column such that saline water accumulates in a lower region of the distillation column rather than within the reboiler;

removing accumulated saline water from the lower region of the distillation column; and

performing at least one cleaning operation on the reboiler selected from: circulating heated hydrocarbon fluid through the reboiler, introducing steam or chemical descaling agents into the reboiler, mechanically cleaning internal surfaces of the reboiler, removing a heating element from the reboiler for mechanical cleaning or replacement, or applying ultrasonic energy to the reboiler to dislodge salt or scale deposits.

13. The method of claim 12, wherein mechanically cleaning internal surfaces of the reboiler comprises inserting a cleaning tool into the reboiler through a flange opening without fully disassembling the reboiler.

14. The method of claim 12, wherein applying ultrasonic energy to the reboiler comprises transmitting ultrasonic energy at a frequency effective to disrupt salt crystal adhesion to internal reboiler surfaces.

15. The method of claim 14, wherein applying ultrasonic energy to the reboiler occurs while hydrocarbon processing continues within the reboiler.

16. The method of claim 12, further comprising detecting accumulation of salt or scale within the reboiler based on at least one of an increased pressure drop across the distillation column or an increased power consumption of a heating element within the reboiler, and initiating the at least one cleaning operation in response to the detecting.

17. The method of claim 12, further comprising injecting desalting and de-emulsion additives into at least one of the separation vessel, the distillation column, or the reboiler to facilitate separation of dissolved salts into a water phase.

18. A desalting system for processing wellhead fluid, the system comprising:

a separator configured to separate the wellhead fluid into wastewater, liquid hydrocarbons, and gaseous hydrocarbons;

a distillation column connected to the separator and configured to receive the liquid hydrocarbons;

a reboiler connected to the distillation column and comprising a heating element;

a programmable logic controller configured to monitor operating parameters of the desalting system and detect accumulation of at least one of salts, scale, or fouling within the desalting system; and

a cleaning system configured to introduce at least one of heated fluid, steam, or chemical descaling agents into at least one of the distillation column or the reboiler in response to detection of accumulation by the programmable logic controller.

19. The desalting system of claim 18, wherein the programmable logic controller is configured to detect accumulation based on at least one of an increased pressure drop across the distillation column or an increased power consumption of the heating element.

20. The desalting system of claim 19, wherein the programmable logic controller is further configured to send a notification to an operator interface recommending at least one of an external hot oil wash or a comprehensive refurbishment based on at least one of a configurable timer or performance degradation below a configurable threshold.