8.01.00 Oil Refining Process
8.02.00 Natural Gas Processing
8.03.00 Bulk Petrochemicals and Intermediates
Fuel oils are transported from oil refineries to end-users via a complex distribution system. Identifying the fuel type is a necessity, as different types of fuels are handled and passed through these distribution systems. The fuels are directed into the appropriate product tanks at the discharge end of the system. Accurate and reliable interface detection is required to ensure that each product ends up in the correct tank, as product contamination can be very costly.
Ref. 8.01.01 Oil Pipeline Interface Detection (pdf)
Hydrotreating is a refining process used to purify and saturate olefins and aromatics in all final and intermediate refinery feedstocks. These include diesel, jet fuel, naphtha, gas oil, and coker feed. The impurities removed include sulfur, nitrogen and metals. The purpose of saturating the olefins and aromatics is to reduce their presence in the hydrocarbons, and to improve the feed stock to the other refinery processes such as the catalytic cracker. The process also has the benefit of mild cracking of heavier components.
Ref. 8.01.02 Hydrotreaters / Aromatic Content Measurement (pdf)
Motor fuel alkylation using sulfuric acid (H2SO4) or liquid hydrofluoric acid (HF) is one of the oldest catalytic processes used in petroleum refining. The purpose of the alkylation is to improve motor and aviation gasoline properties (higher octane) with up to 90% lower emissions compared to conventional fuel usage. The problem with HF is that the catalyst forms a hazardous air pollutant when released as a superheated liquid, while H2SO4 does not. Therefore nearly 90% of all alky units built since 1990 have adopted the H2SO4 technology. The leading H2SO4 alky unit licensor, with a 90% share of the market, is DuPont (Stratco®). Another licensor is EMRE (Exxon Mobile Research Engineering, formerly K.W. Kellogg).
Ref. 8.01.03 Sulphuric Acid Alkylation (pdf)
Chemical plants and refineries receive or deliver many different liquid hydrocarbons, including Natural gas Liquids (NGLs) which are transported via pipeline, railcar, tanker trucks and/or ship. Many of these products are very similar in properties and appearance, therefore, proper identification or interface detection of these hydrocarbons at transport locations that handle multiple products is important to ensure good quality assurance. Two typical products that require proper interface detection are n-butane and isobutane. These are the two structural isomers of butane meaning they have the same molecular formula but different arrangement of the chemical structural
Ref. 8.01.05 Liquid Hydrocarbon Identification (pdf)
8.01.06 KOH Scrubbing of Acidic Gas
One of the most emitted by industry acids is the Hydrofluoric acid (HF). HF alkylation unit generates gas vapours which neutralized prior to their burning in the flare. The presence of HF can create high corrosion rates in flares stacks, moreover, any release of HF into the air must be eliminated. Due to safety reasons HF removal must be carried out. Wet scrubbing is considered to be one of the most effective ways of capture acidic gases. In order to remove HF acid a caustic solution must be added, e.g. Potassium Hydroxide (KOH). KOH forms strongly alkaline aqueous solution which acts as a reactive agent neutralizing the acids. The products of the chemical reaction is Potassium flouride (KF) which is very soluble in the water. After the gas has been neutralized, it can proceed to burning in the flare stack.
Ref. 8.01.06 KOH Scrubbing of Acidic Gas (pdf)
Natural gas processing consists of separating all the various hydrocarbons and fluids from the pure natural gas to produce what is known as “pipeline quality” dry natural gas. It means that before the natural gas can be transported, it must be purified and most of the associated water must be removed. Most of the liquid, free water associated with extracted natural gas, is removed by simple separation methods at, or near, the wellhead. However, the removal of the water vapour, which exists in natural gas solution, requires a more complex treatment. This treatment consists of “dehydrating” the natural gas, which usually involves one of two processes: either absorption or adsorption.
Ref. 8.02.01 Glycol Dehydration (pdf)
Natural gas contains significant amounts of hydrogen sulfide (H2S) and carbon dioxide (CO2). Natural gas is also referred to as “sour gas” because of its strong odor, caused by the sulfur content. These sulfur compounds render it extremely harmful, even lethal, to breathe. Natural gas can also be extremely corrosive. Carbon dioxide must be removed before the gas can be transformed into liquid form (liquefaction LNG) for transportation. Liquefaction results in an extremely low temperature (-161°C or -258°F) which carbon dioxide can freeze in and plug the lines. Amine gas treating, also known as gas sweetening and acid gas removal, refers to a group of processes that use aqueous solutions of various amines to remove H2S and CO2 from gases. It is a common unit process used in refineries, petrochemical plants, natural gas processing plants and other industries. The acid gas absorption in amine solution is conducted using a two column operation: the first column is used to absorb the acid gas into the absorbent amine, the second column is used to regenerate the amine. The process relies on counter current flow to achieve optimum mixing. A lean solution (low acid gas) enters the top of the absorber and flows to the bottom; acid gas enters the bottom of the absorber tower and bubbles to the top. The rich amine (high acid gas) enters the stripper, where the acid gases are released and the “clean” amine is returned to the absorber. The acid gases collect and exit at the top of the stripper.
Ref. 8.02.02 Amine Gas Treating: H2S and CO2 Removal (pdf)
Continuous on-line monitoring of the Refractive Index in lube oil plants allows highly efficient refining process control. Before the development of the K-Patents Process Refractometer PR-23-GP, operators used to do waxy raffinates Refractive Index analysis with a laboratory refractometer. This analysis is described in the ASTM D 1747-89 Test Method for Refractive Index of Viscous Materials. When manufacturing different kinds of Viscosity Index (V.I.) oils, it has been established through laboratory experimentation that the Refractive Index (R.I.) of waxy raffinates should remain within defined limits. The operators need to adjust the process temperatures of the different catalytic beds to maintain the Refractive Index of the waxy raffinates within these limits.
Ref. 8.03.01 Lube Oil Refining Process (pdf)