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EP-4735556-A2 - METHOD OF OPERATING A PRETREATED PIPELINE OR APPARATUS

EP4735556A2EP 4735556 A2EP4735556 A2EP 4735556A2EP-4735556-A2

Abstract

A method of operating a pipeline or apparatus is carried out by subjecting a pretreated component of a pipeline or apparatus to electrochemical corrosion protection. The pretreated component is that having surfaces previously treated with a coating of a treatment composition of a colloidal particle dispersion having inorganic nanoparticles with an average particle size from 500 nm or less that exhibit properties of Brownian motion. At least some of the inorganic nanoparticles of the treatment composition are ionically charged nanoparticles. The surfaces of the pretreated component are fresh surfaces or surfaces where any residues or deposits that have been previously formed on the surfaces from prior material contact have been removed prior to being treated.

Inventors

  • ALLRED, JAMES A., JR.

Assignees

  • PIG SWEEP, LLC

Dates

Publication Date
20260506
Application Date
20240627

Claims (20)

  1. 1. A method of operating a pipeline or apparatus, the method comprising: subjecting at least one pretreated component of a pipeline or apparatus to electrochemical corrosion protection, the at least one pretreated component having surfaces previously treated with a coating of a treatment composition of a colloidal particle dispersion having inorganic nanoparticles with an average particle size from 500 nm or less that exhibit properties of Brownian motion, at least some of the inorganic nanoparticles being ionically charged nanoparticles, the surfaces being fresh surfaces or surfaces where any residues or deposits that have been previously formed on the surfaces from prior material contact have been removed prior to being treated.
  2. 2. The method of claim 1, wherein: the inorganic nanoparticles are encapsulated in a surfactant.
  3. 3. The method of claim 1, wherein: the pipeline or apparatus or portions thereof are buried beneath a surface.
  4. 4. The method of claim 1, wherein: the ionically charged nanoparticles are cationic nanoparticles.
  5. 5. The method of claim 4, wherein: the ionically charged nanoparticles are anionic nanoparticles.
  6. 6. The method of claim 1, wherein: inorganic nanoparticles have an average particle size from 300 nm or less.
  7. 7. The method of claim 1, wherein: the inorganic nanoparticles have an average particle size from 0.1 nm to 300 nm.
  8. 8. The method of claim 1, wherein: the pipeline comprises at least one of a gas pipeline and a liquid petroleum pipeline.
  9. 9. The method of claim 1, wherein: the surfaces are treated with a coating of the treatment composition having a thickness from 0.1 mil (0.0025 mm) to 10 mils (0.2540 mm).
  10. 10. The method of claim 1, wherein: the treatment composition has a pH from 6 to 7.
  11. 11. The method of claim 1, wherein: the apparatus is at least one of a man-made body, a man-made structure, a tank, a storage tank, a vessel, a storage vessel, a mixing vessel, a container, a valve, a pipe, a drum, an aquatic vessel, a reactor, a combustor, a refrigeration unit, a cooling unit, a heat exchanger, a boiler, a radiator, a separator, an evaporator, a pump, a compressor, a tower, a column, a cooling tower, a filter, a filtration unit, a slug catcher, a Joule Thomson (JT) system, a cracking unit, a pyrolysis unit, a refining unit, a coalescer, a dehydrator, an amine unit, an amine treatment system, a chemical processing system, a food processing system, a gas processing system, a petroleum processing system, a biomatter processing system, and a water processing system.
  12. 12. The method of claim 1, wherein: the inorganic nanoparticles are present in the treatment composition in an amount from 0.001 wt% to 60 wt% by total weight of the treatment composition.
  13. 13. The method of claim 1, wherein: the inorganic nanoparticles are present in the treatment composition in an amount from 0.01 wt% to 10 wt% inorganic nanoparticles by total weight of the treatment composition.
  14. 14. The method of claim 1, wherein: the treatment composition further comprises at least one of a surfactant, an amphoteric surfactant, an ionic surfactant, an anionic surfactant, a cationic surfactant, a nonionic surfactant, a drying agent, a glycol, triethylene glycol, propylene glycol, ethylene glycol, glutaraldehyde, a bacteria-reducing agent, a biocide, a pH adjuster, water, an alcohol, a solvent, a dispersant, a non-terpene oil-based moiety, a terpene, a terpenoid, and limonine.
  15. 15. The method of claim 1, wherein: the treatment composition is free of any tetrakis(hydroxymethyl)phosphonium chloride (THPC), tetrakis(hydroxymethyl)phosphonium sulfate (THPS), methanol and ethanol.
  16. 16. A method of pretreating a component of a pipeline or apparatus, the method comprising: selecting a colloidal particle dispersion having inorganic nanoparticles with an average particle size from 500 nm or less that exhibit properties of Brownian motion, at least some of the inorganic nanoparticles being ionically charged nanoparticles; selecting a component of a pipeline or apparatus configured to undergo electrochemical corrosion protection; and contacting the surfaces of the component of the pipeline or apparatus with a treatment composition comprising the colloidal particle dispersion, the surfaces of the pipeline or apparatus being surfaces of a fresh pipeline or apparatus and/or surfaces of a non-fresh pipeline or apparatus where any residues or deposits that have been previously formed on such surfaces of the non-fresh pipeline or apparatus from prior material contact have been removed.
  17. 17. The method of claim 16, wherein: the ionically charged nanoparticles are at least one of cationic nanoparticles and anionic nanoparticles.
  18. 18. The method of claim 16, wherein: the inorganic nanoparticles have an average particle size from 0.1 nm to 300 nm.
  19. 19. The method of claim 16, wherein: the at least one component is treated with a coating of the treatment composition having a thickness from 0.1 mil (0.0025 mm) to 10 mils (0.2540 mm).
  20. 20. The method of claim 16, wherein: the apparatus is at least one of a man-made body, a man-made structure, a tank, a storage tank, a vessel, a storage vessel, a mixing vessel, a container, a valve, a pipe, a drum, an aquatic vessel, a reactor, a combustor, a refrigeration unit, a cooling unit, a heat exchanger, a boiler, a radiator, a separator, an evaporator, a pump, a compressor, a tower, a column, a cooling tower, a filter, a filtration unit, a slug catcher, a Joule Thomson (JT) system, a cracking unit, a pyrolysis unit, a refining unit, a coalescer, a dehydrator, an amine unit, an amine treatment system, a chemical processing system, a food processing system, a gas processing system, a petroleum processing system, a biomatter processing system, and a water processing system.

Description

METHOD OF OPERATING A PRETREATED PIPELINE OR APPARATUS TECHNICAL FIELD [0001] The disclosure relates to methods of pretreating pipelines, apparatuses, systems, process equipment or components thereof using particular treatment compositions. BACKGROUND [0002] Pipelines are used throughout the world to efficiently and economically transport large quantities of fluids over great distances. Some of these pipelines may be hundreds and sometimes thousands of miles in length, particularly those used to transport crude and refined petroleum oil, natural gas, chemicals, etc. Friction between the interior surfaces of the walls of the pipeline and the fluid flowing through the pipeline can result in significant pressure drops and a decrease in fluid flow rate over the length of the pipeline. As a result, pumps or compressors typically must be staged along the length of the pipeline to repressurize the fluid and increase fluid flow. Higher friction levels decrease the flowrate within the pipeline, requiring more demand on pumps and compressors and/or requiring larger and/or more pumps or compressors to transport a given fluid through the pipeline, thus increasing the cost of constructing and operating the pipeline. [0003] Pipelines used for these fluids are typically formed from metals, such as carbon steel. While the exterior surfaces of the pipelines are typically painted or covered with a protective coating to prevent corrosion, the interior of the pipelines are typically unprotected or bare metal so that they are subject to corrosion. Cathodic corrosion protection, where a small electrical current is applied to the pipeline so that it becomes cathodic, can offer some protection against internal pipe corrosion, but this does not prevent all corrosion. [0004] Deposits may also begin to form on the surfaces of pipelines and other process equipment from prolonged contact with the transported or process fluids. These deposits also tend to increase friction and increase pressure drop and reduce fluid flow. Additionally, the deposits that form on the interior surfaces of the pipeline can form corrosion cells in which under-deposit corrosion can occur. Such corrosion cells require the presence of water in the pipeline, which forms the electrolyte in the corrosion cell. This water is typically present in the pipeline as entrained water within the transported fluids. Fluids that are conveyed through pipelines typically contain some water. Even dry natural gas has some amount of water (e.g., 4-7 lbs water/MMSCF of gas or 0.064-0.112 kg water/1000 SCM of gas) that allows the formation of corrosion cells. The water can penetrate these surface deposits becoming entrapped under the deposit to form the corrosion cell and facilitate the under-deposit corrosion. [0005] There are various sources of these corrosion causing materials. This can include carbon dioxide (CO2) and hydrogen sulfide (H2S) that may be present in the transported fluids. Carbon dioxide hydrates in the presence of water to form carbonic acid (H2CO3). The acid in turn reacts with the iron or steel to form corrosion. The hydrogen sulfide also reacts with the iron or steel material of the pipeline to form iron sulfides, thus corroding and degrading the pipe. These materials can penetrate the surface deposits to form the corrosion cells. [0006] Microbiologically influenced corrosion (MIC) from microbes or bacteria that may be present in the fluids is also a source of corrosion. These microbes or bacteria may attach to the internal surfaces of the pipeline or under the surface deposits and grow as a colony to form a biofilm on the surfaces of the pipe. These microbes are often present in fluids produced from subterranean formations, such as oil and gas wells. The microbes are typically chemoautotrophs, which obtain energy by the oxidation of electron donors from their surroundings. One type of such microbe is sulfate-reducing bacteria (SRB). SRBs utilize sulfate ions (SO42 ) that are reduced to H2S. Water within the pipeline will interact with the metal surfaces to create a layer of molecular hydrogen. The SRBs through anaerobic respiration will then utilize the sulfate ions so that the hydrogen layer on the walls of the pipeline is oxidized to H2S, which in turns reacts with iron to form iron sulfides. Another type of MIC that leads to corrosion in pipelines is that produced by acid producing bacteria (APB). ABPs undergo anaerobic fermentation instead of anaerobic respiration, producing acids as part of their growth cycle. These produced acids lead to the acid corrosion of the metal materials of the pipeline. [0007] To remove these deposits, coatings, and other detrimental materials, a maintenance program is carried out. This essentially involves passing a projectile, commonly referred to as a “pig,” down the interior of the pipeline so that the deposits are physically scraped off the sides of the pipeline as the pig is moved through the pipeline. This process, ref