Automated MT Titrator Accommodates Reserve Alkalinity

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MANTECH’s Dynamic MT-Series Systems can modify titrations to our customer’s own customized end points for determination of Reserve Alkalinity of Coolants.

Recently, one of MANTECH’s Canadian customers received a software upgrade to create a custom pH titration method for their MT-100. Modifications were made to accommodate an end point of pH 5.5 for Reserve Alkalinity of Coolants; an end point of pH 5.2 for Active Alkalinity of Amines (where DEA, DIPA, and MDEA Factors were also reported); and an end point of pH 3.0 for the Determination of Free CO2 in Glycols, Amines, Sulphinol, and Water.  MANTECH also accommodated a special request to add an isopropyl alcohol (IPA) wash step to their MT-Series Autosamplers dynamic rinsing routine to save the analysts time.  This IPA wash step automatically cleans the electrodes of bitumen/ hydrocarbons that contaminated their water.

Reserve Alkalinity:

Reserve alkalinity is the number of millilitres, [to the nearest 0.1 mL] of 0.100 N hydrochloric acid (HCl) required for the titration to a pH of 5.5 of a 10-mL sample of coolant, antirust, or coolant additive.

Reserve alkalinity is a term applied to engine coolants and antirusts to indicate the amount of alkaline components present in the product. It is used for quality control during production, and values are often listed in specifications. When applied to used solutions, reserve alkalinity gives an approximate indication of the amount of remaining alkaline components. ”

                                                                                                                                                                                                                                                                                        – ASTM

Oil & Gas Industry:

Amine gas treating, (also known as amine scrubbinggas sweetening and acid gas removal), refers to a group of processes that use aqueous solutions of various alkylamines (commonly referred to simply as amines) to remove hydrogen sulfide (H2S) and carbon dioxide (CO2) from gases.[1][2][3] It is a common unit process used in refineries, and is also used in petrochemical plants, natural gas processing plants and other industries[4].

Processes within oil refineries or chemical processing plants that remove hydrogen sulfide are referred to as “sweetening” processes.  This is where the odor of the processed products is improved by the absence of hydrogen sulfide. An alternative to the use of amines involves membrane technology. However, membrane separation is less attractive due to the relatively high capital and operating costs as well as other technical factors.[5]

Many different amines are used in gas treating:

The most commonly used amines in industrial plants are the alkanolamines DEA, MEA, and MDEA. These amines are also used in many oil refineries to remove sour gases from liquid hydrocarbons such as liquified petroleum gas (LPG).

MEA and DEA are primary and secondary amines. They are very reactive and can effectively remove a high volume of gas due to a high reaction rate. However, due to stoichiometry, the loading capacity is limited to 0.5 mol CO2 per mole of amine.[7] MEA and DEA also require a large amount of energy to strip the CO2 during regeneration, which can be up to 70% of total operating costs. They are also more corrosive and chemically unstable compared to other amines.” 

                                                                                                                                                                                                                                                                                        – Wikipedia

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