Crude oil or slop oils often contain very stable emulsions, which are fine dispersions of oil and water. Emulsions can cause severe fouling and corrosion problems in distillation columns, heat exchangers and reboilers. In general, the emulsion is stabilized by a variety of contaminants and additives from upstream operations. Common stabilising components for an unwanted emulsification are asphaltenes, resins, porphyrins, wax crystals or fatty acids. Such components may react as surfactants with a drop size in the micron range.

Pumped crude oil from the well contains water in emulsified and free state. Untreated crude oil still comprises water and salts when stored in tank farms. The crude oil emulsion consists of small globules of water surrounded by the oil. Crude oil separation to remove oil from water is a very important application step. The emulsion breaking performance is influenced by the composition of the emulsion phase and contaminants. Reduction of impurities and salts from the crude oil are directly related to less corrosion and fouling.  This will improve the desalting efficiency, oil recovery and crude oil separation performance. The bigger droplets will finally settle down to be removed as desalter effluent water. Many crude oils contain a high concentration of solids (BS&W = Basics, Sediments & Water). Such crude oils are difficult to process. Negative impacts are electrical desalter upsets, fouling and corrosion of the downstream distillation equipment.

An adequate residence time is essential for the crude oil separation to remove oil from water. Crude oil separation into two phases by gravity is a very slow process. The physical process can be accelerated by using a suitable chemical emulsion breaker programme. The additives used are termed demulsifiers, emulsion breakers or wetting agents. These chemicals are surfactants, which migrate to the oil/water interface. Nonionic surfactants having both of lipophilic and hydrophilic groups are mainly used. They break the crude oil emulsions that water droplets aggregate to form bigger water drops. That drops are large enough to gravitationally separate them from the oil.

By adding Kurita´s emulsion breaker chemicals you will already achieve far better results. Excellent oil recovery of slop oils and a better dewatering and desalting of crude oils are important measures. The use of the emulsion breaker reduces the risk of corrosion and fouling in the downstream refining operations. Our high-performing programmes accelerate the crude oil separation. This improves the emulsion breaking process to remove oil from water. The risk of undesired oil carry-over into the desalter effluent water will be minimised. The desalted crude oil contains less water and fewer salts with a lower risk of corrosion and fouling. A very good desalting efficiency with increased oil recovery is the key element for the slop oil or desalter treatment. Your benefits are a higher profitability with increased utilisation of the downstream equipment.

Foaming is a physical incorporation of a gas in a liquid. Foam is stabilised by solids, hydrocarbons, heat stable salts and other contaminants. Process chemicals with surfactant properties stabilise the foam too. Corrosion inhibitors, dispersants and emulsion breakers have surfactant characteristics. Foam formation may cause health and safety issues. Excessive foaming may lead to pump cavitation, pump failure and loss of process control.

The liquid film surrounds the gas creating a bubble. The bubble wall or film is a dynamic system, constantly stretching and contracting. After stretching is has a high surface tension. The thinner film section contains less liquid. Immediate action is required to prevent or destabilise the foam. Based on definition antifoams prevent foam formation. Defoamers break existing foam.

Powerful antifoam additives are intended to act with defoaming and antifoam properties. Antifoaming agent programmes increase the elasticity of the formed film layer. The antifoam provides a surfactant diffusion. It creates a film with a built-in weakness to become unstable. The defoaming agent properties destroy the foam formation immediately and prevent a new formation of foam.

Typical antifoaming agent applications are:

• Crude distillation tower and vacuum tower
• Delayed coker and visbreaker
• thermal cracker and bitumen (asphalt) plants
• Lube oil extraction and propane deasphalting
• Caustic scrubber, sour water strippers and amine units

Delayed cokers and amine units are process units, where antifoams are steadily used. Foam carry-over from the coke drum must be avoided. Otherwise, that could results in an unexpected shutdown. PDMS based antifoams are mainly used at delayed cokers. They are the preferred products because of the high thermal stability. A suitable PDMS antifoam thermally decomposes, but the fragments still have antifoam properties. Silicone is a catalyst poison, why the dosing must be done carefully.  

Foaming in amine units is an omnipresent threat. The addition of liquid hydrocarbons to amine solutions is a primary cause for foaming. Foam carry-over in the absorber should be avoided. In amine units, PDMS antifoams show very good foam control results. Polyol based antifoams are often used as well.

Kurita provides highly efficient antifoaming agent programmes. Defoaming agents immediately displace the foam stabiliser and locally burst bubbles. This reduces the wall viscosity and lowers the electrostatic surface potential. Defoaming agent characteristics are, that they are non-toxic and not harmful to products. Chemically non-reactive properties are required. The antifoam should be easy to feed with non-volatile characteristics.

Types of antifoams are based on hydrocarbons, silicone or organic chemistry. Organic antifoams are polyols, fatty alcohols and esters. Silicone antifoams are very efficient antifoaming agent types. Many types of silicones are available like silicone fluids, emulsions, hydrophobised or substituted fluids.

Kurita ´s defoaming agent formulations contain:

• Oil-free components
• Natural oils or Mineral oils
• Silicone containing or silicone-free active substances
• Polydimethylsiloxane (PDMS)

Corrosion attack is an omnipresent threat to oil refineries and petrochemical plants. Corrosion is defined as a gradual destruction of a material or substance. Corrosion costs companies around the world billions of dollars. It may lead to significant loss of production, cost of maintenance and expensive repairs. Some technologies increase the corrosion resistance of the distillation equipment. Corrosion resistant alloys (CRA), coating of the metal surfaces or cathodic protection offer good corrosion prevention. Due to its low purchase costs most distillation equipment is made of carbon steel. Carbon steel is very unstable in acids which lower the corrosion resistance of the metal surface. Corrosion rates increase sharply when pH drops down below 7. Corrosive components are hydrogen chloride, hydrogen sulfide, ammonium chloride, ammonium bisulfide, carbon dioxide and organic acids.

Typical corrosion forms in refineries are, in particular:

• Local corrosion or Pitting
• Hydrogen Induced Corrosion (HIC)
• Stress Corrosion Cracking (SCC)
• Erosion
• Cavitation

Aqueous corrosion is caused by the electrochemical processes of two half-cell reactions. The basic corrosion cell requires an anode, cathode, metallic conductor and electrolytes. If one of these is missing, aqueous corrosion will not occur. Corrosion inhibitors are used for corrosion prevention. They can help to stop or decelerate the function of a corrosion cell. Filming amines and neutralising amines provide excellent corrosion protection and are well-established treatment programmes.

Film-forming amines are the most common corrosion inhibitors. They form a protective layer on the metal surface. This results in a better corrosion protection by increasing the corrosion resistance. Oil soluble filming amines are well established in oil refineries and petrochemical plants. They need hydrocarbons from the process stream to form a protection layer. They are used in hydrocarbon systems with lower water content. Process systems with high water content are vacuum overheads, sour water strippers, water quench columns or amine units. Water-soluble filming amines offer excellent corrosion protection properties. Kurita provides high-performing oil soluble and water soluble amine for corrosion protection.

Historically, ammonia was used as a neutralising amine. Ammonia has a number of negative properties and increases the risk of ammonium salt fouling. Ammonia is a volatile amine and will not provide a safe neutralization during condensation. Kurita´s modern neutralising amine blends provide excellent corrosion protection and very good buffering capacities. They operate by reacting with any acid constituent in a straight forward chemical neutralization. The neutralising amine shifts the pH from very corrosive conditions to levels which are easier to control. They demonstrate an easier pH control and better handling.

The presence of chlorides or salt formation can lead to damage or production losses in oil refineries. Usually, these salts are ammonium chloride (NH₄Cl) or ammonium bisulfide (NH₄HS). Process units suffering salt fouling or corrosion are crude distillation units, hydrotreaters, hydrocrackers, FCC units and reformer units. Salt formation is frequently observed on the tube walls, fractionator trays, piping and heat-exchanger surfaces. The salt deposit formation leaves a highly concentrated, thick, acidic, viscous solution. This can result in under deposit corrosion (pitting corrosion) as the salt deposit absorbs moisture. Ammonium chloride or ammonium bisulfide salts are highly corrosive. Wash water systems are installed for the reduction of a salt deposit risk. It is certainly a good step in the right direction to remove as many salts as possible. Ammonium salts are generally readily soluble in water. But in the presence of hydrocarbons salt deposits often cannot be completely removed.

Kurita has developed a unique chemical treatment programme, known as Technologie ACF. Liquid formulations of a very strong organic base are used to avoid acid corrosion or salt formation. The organic base ACF reacts preferentially with strong acids such as hydrochloric acid (HCl) or its ammonium salts. The favoured reaction of ACF with HCl is a significant benefit in process units with naturally high H₂S concentrations. At locations, where salt formation occurs, ACF displaces the weaker base ammonia by forming a liquid ACF salt. The reaction products have very high moisture absorption characteristics (highly hygroscopic). ACF salts have a very low corrosivity and can be removed easily with free water. 

ACF treatment programmes are used continuously for the prevention of salt formation and corrosion attack. ACF reacts immediately with acidic components and minimises the salt deposit potential. This allows refiners to run the distillation units with a higher productivity and higher reliability.

FCC units frequently suffer from ammonium salt fouling. In many cases, ammonium chloride salts increase the pressure drop or cause flooding of the top trays. Removal of deposited salts during normal process operations is particularly very useful in crude oil refinery processes. Traditional tower washing procedures may remove water-soluble salts. But the feed rate must be significantly reduced during this time. Produced naphtha, sometimes also light cycle oil(LCO), goes off-specification. It must be reprocessed with increased costs. When ammonium salt fouling is detected, an online cleaning with ACF is the first choice to dissolve the deposited salts from the top trays. Throughput reductions are not required. Deposited salts are dissolved and mobilised in a short period of time. A rapid decrease of the differential pressure typically demonstrates the success of the online treatment.

Fouling is a serious problem at oil refineries. It may lead to insecure operating conditions with high production losses. Shortened runtime is a drawback, which requires cleaning procedures. In some cases, a material exchange could be necessary. Mechanical designs, process conditions and feed qualities influence the fouling potential and operation. Typical fouling components are waxes, asphaltenes, carbon deposits, stable emulsions, inorganic solids or polymers. In oil refineries, most organic fouling is caused by asphaltene precipitation, including coke formation. Asphaltenes are sensitive to shearing forces and electrostatic interactions. Crude preheat trains, vacuum column bottoms and downstream heat exchangers can plug. The economic implications are significant and can cost millions of dollars.

The best strategy to avoid asphaltene precipitation is the stabilization of asphaltenes. Kurita´s asphaltene dispersants keep the particles small avoiding agglomeration. They work by surrounding the asphaltene molecules, similar to the natural resins in crude oil. This keeps the hydrocarbons in a colloidal system. The asphaltenes stay in a disperse phase why asphaltene precipitation is prevented.

Gasification with partial oxidation (POX) is an old technology. The process has been developed for over 200 years. It is far older than modern oil refineries for the production of fuel oils. Gasification is an exothermic, non-catalytic reaction of the feedstock and limited amount of oxygen. In a highly reducing atmosphere hydrocarbons are converted into electric power, synthesis gas, fuels, fertilizers and chemicals. The produced raw gas has a temperature of about 1300 – 1400°C. Severe fouling of the syngas cooler because of carbon deposits may result in an unwanted shutdown. Under such process conditions commonly used antifoulants will decompose at once with no effect. Kurita developed an antifoulant technology for the POX process. This fuel additive has an excellent thermal stability and reduces carbon deposits. It minimises the fouling potential in the waste heat reboilers by softening the deposits. This keeps the coke particles small to be transported with the syngas.

In oil refineries, small amounts of oxygen can cause or accelerate polymerisation. Our antioxidants terminate the peroxide radicals which are formed when oxygen reacts with hydrocarbons. This prevents gum formation derived from thermal and catalytic cracking operations. The antioxidants act as chain-stoppers and stop the initiation or propagation reactions of the radical reaction process. Kurita provides a complete range of programmes consisting of dispersants, oxygen scavengers, stabilizers, antioxidants and metal deactivators.

Kurita adapts the treatment concepts to your needs to prevent fouling and operational limitations. Our fouling inhibitors have a good thermal stability. They can be used as well at higher temperatures, where precipitation, polymerisation or coke formation would occur.

Hydrogen sulfide (H₂S) is a naturally occurring gas obtained in many crude oils. By degradation of sulfur compounds in the oil additional hydrogen sulfide can be released. That mainly happens when sulfur compounds come in contact with water at high temperatures. Hydrogen sulfide is a toxic, colourless gas with a rotten egg odour. It is detectable a low ppb level and may be present in all refinery process streams. Mercaptans (RSH) are a common contaminant of lighter hydrocarbon components. They are less reactive than hydrogen sulfide but limit the product specifications as well. Both contaminants are corrosive to metals, can poison catalysts and are very offensive smelling.

At high temperatures, bitumen (asphalt) as the heaviest refinery product can release larger concentrations of H₂S to the vapour phase. During plant shutdowns, tanks, containers and distillation columns must be opened to allow necessary on-site inspections. The concentration of H₂S in the headspace of storage tanks can change because of temperature, agitation, viscosity and tank level. Hydrogen sulfide and mercaptan compounds need to be safely removed prior to any entry and inspection.

Hydrogen sulfide presents significant safety, operational, environmental and compliance issues. To meet specifications and safety requirements, hydrogen sulfide removal from refinery gas, distillates and fuels is necessary. The use of a hydrogen sulfide scavenger is necessary to lower the risks. Commercial neutralising amines are often used as H₂S scavenger products, but they are not selective for hydrogen sulfide removal. At high temperature, such H₂S scavenger products have reversible properties and will release the H₂S again. Requirements for a good H₂S scavenger are preferably oil-soluble additives, rapid and non-reversible reactions and high thermal stability.

Increased concentrations of hydrogen sulfide or mercaptans in end products reduce their quality significantly. These “low-quality” end products have to be sold at a lower price. In the worst case, they need to be reused in refinery processes. However, it means a loss of production why a high-performing H₂S scavenger can be the first choice for the hydrogen sulfide removal. Kurita‘s hydrogen sulfide scavenger programmes eliminate these inconvenient components. For the removal of mercaptans very efficient chemical programmes are also available.

Our H₂S scavenger products provide a rapid reaction with minimal mixing by increasing the quality and the value of the finished products. Our treatment programmes rapidly remove hydrogen sulfides and mercaptans in the product streams.

Kurita´s tailored hydrogen sulfide scavenger products allow a safe and timely inspection of the systems. The very low dosing rates and cost-effective treatment provide significant benefits for you in a variety of products. According to your specifications, Kurita will supply metal-free H₂S scavenger technologies which are completely soluble in oil or water with good anticorrosion properties. Our hydrogen sulfide scavenger products have a high thermal stability. If required, Kurita can supply non-nitrogen containing hydrogen sulfide scavenger versions.

Biofouling prevention is required, when fuels contain organisms, that can metabolise fuel compounds. The most common microorganisms are fungi and bacteria. They typically live in water but use fuel as a nutrient and oxygen source. The microbes can produce acids, carbon dioxide, hydrogen sulfide and large slime-like growth colonies. Fungi can survive in a low oxygen content environment. Often they are found in combination with bacteria such as Pseudomonas species. Whenever microbes establish themselves, they collect together with an extensive growth. The large areas of growth are called plaques. Plaques are found on the side-walls and on the bottom of the storage tanks.

Fuel additives are necessary for biofouling prevention and corrosion control. Underneath the plaques microbiologically influenced corrosion (MIC) can occur. The metabolic by-products corrode the metal, where pits are produced. Microbes live in pits and extend the corrosion process. In extreme cases, holes through the metal surface will be observed. Microorganisms create severe problems including filter plugging, why fuel additives are used. Most water-based biocides degrade rapidly under alkaline pH conditions. Some commercial biocides degrade in a few days at pH 7. Therefore retreating will be necessary that is detrimental and creates additional costs.

Kurita provides high-performing oil soluble fuel additives to stop corrosion and biofouling. They are applied for biofouling prevention in diesel fuels, heating oils, residual fuels and other petroleum distillates. The growth of bacteria and fungi is eliminated and/or prevented. Our biocides are designed to kill aerobic and anaerobic fungi, bacteria, yeasts and sulphate-reducing bacteria. Benefits are very good anti-corrosive properties with excellent protection against microbial material degradation and sludge formation. Kurita´s fuel biocides are completely biodegradable (OECD 301D / EEC 84/449 C6). They contain no nitrate, nitrosating agents or organically bound chlorine and have no effect on the AOX value.

When hydrogen sulfide is released, Kurita´s oil soluble H₂S scavengers rapidly bound the hydrogen sulfide and mercaptans (RSH). The cost-effective treatment provides very low treat rates with high efficacy and thermal stability in fuels.

Kurita´s distillate fuel oil stabilisers are oil soluble additives. Used at a low dosage they stabilise cracked and straight run distillate fuels. The antioxidant properties provide good colour stability with maximum sludge control. They have a high thermal stability and provide peak performance in diesel engines and home burners. These fuel additives provide protection against injector sticking, clogged filters, strainers, nozzles and fouled burner tips. They are not extracted by water under normal handling conditions with no contribution to water haze. The active materials are proven by DEF STAN 91-91 in EMEA.

Les raffineries de pétrole et les usines pétrochimiques utilisent un grand nombre d'équipements de distillation différents. Il s'agit de colonnes, de cuves de décantation, de colonnes de distillation, d'échangeurs de chaleur et de systèmes de tuyauterie. L'encrassement est un problème omniprésent. Les inconvénients de l'encrassement sont la réduction du débit, des pertes significatives dans la récupération d'énergie ou la génération d'une augmentation de la chute de pression des colonnes de distillation ou des échangeurs de chaleur. Le nettoyage et la décontamination périodiques sont obligatoires et l'équipement doit être vérifié en vue d'une maintenance ou d'une réparation.

A planned shutdown is a very labour-intensive time, which often requires several weeks of downtime. Heavy fuel oils, greases, tars or tenacious fouling materials must be removed. Contaminated tanks, columns, heat exchangers or pipelines have to be drained for cleaning and degassing. Fouling deposits may contain hazardous components and harmful gases. Toxic hydrogen sulfide, volatile hydrocarbons or carcinogenic benzene can be released. Iron sulfide (FeS) easily accumulates in pipes, trays, structured packings, heat exchangers and vessels. Due to its pyrophoric nature it can become a serious problem. Iron sulfide has a high potential for spontaneous auto-ignition. It oxidizes exothermally when in contact with air. Most FeS induced fires occur during shutdowns, when the equipment is opened for maintenance and inspection.

La santé, la sécurité et la protection de l'environnement sont des aspects très importants. Il est demandé au personnel responsable de minimiser l'exposition des travailleurs à toute situation où l'auto-inflammation des espèces de sulfure de fer ou des risques pour la santé pourraient être déclenchés. Le contact avec les matériaux décontaminés doit être évité. L'élimination du benzène, du sulfure de fer pyrophorique, du sulfure d'hydrogène toxique et d'autres gaz dangereux est absolument nécessaire pour garantir des conditions de travail sûres. Le respect de la limite inférieure d'explosivité (LIE) doit être assuré.

Kurita propose une large gamme de produits divers tels que des produits chimiques de nettoyage, des agents de dégazage ou des combinaisons de ces produits. La manipulation de nos additifs de nettoyage et de décontamination est facile et sûre pour le personnel d'exploitation. Des agents chimiques de nettoyage très performants, associés à des méthodes de nettoyage et de dégazage sur mesure, sont utilisés pour atteindre ces objectifs en toute fiabilité. Le nettoyage et le dégazage des colonnes et des cuves de distillation peuvent être effectués avec d'excellents résultats en l'espace d'une journée. L'élimination des fiouls lourds, des goudrons, des graisses et d'autres matières tenaces sont des éléments clés du nettoyage. L'élimination complète des gaz dangereux et des risques d'incendie revêt une grande importance. Le nettoyage de la surface métallique sans attaquer l'équipement de distillation est un fait.

La récupération de chaleur est essentielle dans les unités de traitement qui fonctionnent avec des réacteurs. Le nettoyage mécanique des réseaux complexes d'échangeurs de chaleur peut prendre plusieurs jours et les zones inaccessibles ne peuvent être atteintes. En comparaison, les solutions de nettoyage et de dégazage de Kurita permettent d'atteindre les zones inaccessibles. Le nettoyage peut être effectué sur place en une journée. Le travail requis est moins intensif que pour le nettoyage mécanique. Les programmes de nettoyage chimique sur mesure de la série Kurita CD sont utilisés lorsque des résultats de nettoyage très efficaces sont nécessaires. Les échangeurs de chaleur à plaques Packinox ou les échangeurs de chaleur tubulaires Texas Tower nécessitent plus d'efforts de nettoyage que les échangeurs de chaleur classiques. Les concepts de nettoyage de Kurita sont la méthode de choix lorsque les échangeurs de chaleur Packinox ou les Texas Towers doivent être nettoyés.

Le nettoyage mécanique et la décontamination des réservoirs de stockage peuvent nécessiter plusieurs semaines d'immobilisation. En comparaison, le nettoyage chimique et le dégazage réduisent considérablement le temps d'arrêt à quelques jours, ce qui présente un grand avantage économique.

Kurita vous propose des programmes de nettoyage et de dégazage adaptés à vos besoins. Notre personnel qualifié vous aidera dans vos processus de nettoyage et de dégazage. Sur demande, nous fournissons l'équipement nécessaire.