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This video is about the simulation of the Naphtha Hydrotreater in Aspen HYSYS. The major units of the process are:
1. Naphtha Hydrotreater
2. Petroleum Feeder
3. Splitter
You will also learn how we can use two property packages in a single flowsheet.
@ 00:07 Add Petroleum Assay
@ 00:40 Petroleum Feeder
@ 01:40 Two Fluid Package in One Flowsheet
@ 02:41 Flowsheeting
@ 04:27 Naphtha Hydrotreater Inputs
@ 06:00 Connecting Internal External Streams
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Hydrotreating | Naphtha Hydrotreating – Topsoe
Our extensive range of naphtha hydrotreating catalysts and technologies are designed to handle all feedstocks and still ensure easy, reliable, stable, and …
Source: www.topsoe.com
Date Published: 10/10/2021
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Naphtha hydrotreater | McKinsey Energy Insights
The naphtha hydrotreater is a category of hydrotreater that treats heavy naphtha streams, primarily to prepare them as feed to the reformer by removing …
Source: www.mckinseyenergyinsights.com
Date Published: 7/1/2021
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- Date Published: 2021. 11. 3.
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What is naphtha hydrotreating unit?
The naphtha hydrotreating unit uses a cobalt-molybdenum catalyst to remove sulfur by converting it to hydrogen sulfide that is removed along with unreacted hydrogen. Some of the hydrogen sulphide-hydrogen mixture is recycled back to the reactor to utilize the unreacted hydrogen, using a compressor.
What is NHT unit?
The NHT process unit removes sulfur and nitrogen from straight run naphtha downstream of the Crude Distillation process unit (CDU). Removing these impurities involves treating the naphtha with hydrogen to create a suitable feed stock.
What does a hydrotreater unit do?
The purpose of a hydrotreater unit is primarily to remove sulfur and other contaminants from intermediate streams before blending into a finished refined product or before being fed into another refinery process unit.
What is hydrotreating in petroleum refining?
Hydrotreating or hydrodesulfurization refers to a set of operations that remove sulfur and other impurities (Figure 1). During hydrotreating, crude oil cuts are selectively reacted with hydrogen in the presence of a catalyst at relatively high temperatures and moderate pressures.
What is the hydrotreating process?
Hydrotreating is the reaction of organic compounds in the presence of high pressure hydrogen to remove oxygen (deoxygenation) along with other heteroatoms (nitrogen, sulfur, and chlorine).
What is NHT in refinery?
Naphtha hydrotreating (NHT) is one of the critical processes in a crude oil refinery. It removes sulphur and nitrogen compounds from naphtha to avoid poisoning of catalysts in downstream isomerization and reforming processes.
What is distillate hydrotreating?
Hydrotreating processes aim at the removal of impurities such. as sulfur and nitrogen from distillate fuels—naphtha, kerosene, and. diesel—by treating the feed with hydrogen at elevated temperature. and pressure in the presence of a catalyst.
What is kerosene hydrotreating unit?
The kerosene hydrotreater unit is a catalytic chemical process unit used to remove sulfur (S) from kerosene.
What is MS block in refinery?
Axens is recognized as a key global solutions provider in the Motor Spirit (MS) Block providing NHT, C5/C6 Isomerization and reforming processes, combining proven and reliable technologies with advanced catalytic solutions to produce high quality gasoline components meeting the latest Bharat Stage VI gasoline …
What’s the difference between hydrotreating and hydrodesulfurization?
Hydrotreating for sulfur or nitrogen removal is called hydrodesulfurization or hydrodenitrogenation. Hydrotreating processes differ depending on the feedstock available and the catalysts used. Mild hydrotreating is used to remove sulfur and saturate olefins.
What is the difference between hydrocracking and hydrotreating?
There are two types of hydroprocessing as hydrocracking and hydrotreating. The key difference between hydrocracking and hydrotreating is that hydrocracking includes the conversion of high boiling constituents to low boiling constituents, whereas hydrotreating includes the removal of oxygen and other heteroatoms.
What is hydrotreating catalyst?
Hydrotreating catalysts are primarily used to remove sulfur, nitrogen and other contaminants from refinery feedstocks. In addition, they improve product properties by adding hydrogen and in some cases improve the performance of downstream catalysts and processes.
What is hydrotreating of crude oil?
Crude oil hydrotreating is a catalytic process that uses hydrogen at high reaction temperatures and pressures with a high activity catalyst to remove contaminants such as sulfur (S), nitrogen (N), metal (M) and saturate aromatic and olefinic compounds.
What is distillate hydrotreating?
Hydrotreating processes aim at the removal of impurities such. as sulfur and nitrogen from distillate fuels—naphtha, kerosene, and. diesel—by treating the feed with hydrogen at elevated temperature. and pressure in the presence of a catalyst.
What is kerosene hydrotreating unit?
The kerosene hydrotreater unit is a catalytic chemical process unit used to remove sulfur (S) from kerosene.
What is diesel hydrotreating?
Diesel hydrotreating (DHT) or catalytic hydrogen treating is mainly to reduce undesirable species from straight-run diesel fraction by selectively reacting these species with hydrogen in a reactor at elevated temperatures and at moderate pressures.
Where is naphtha used?
As mentioned above, naphtha is commonly used as a solvent. It is used in hydrocarbon cracking, laundry soaps, and cleaning fluids. Naphtha is also used to make varnishes, and sometimes is used as a fuel for camp stoves and as a solvent (diluent) for paint.
California Emphasis Program
This article appears in the November/December 2010 issue of Inspectioneering Journal.
Risk-Based Inspection (RBI) is an emerging technology available to plant engineers and managers as theyapply risk directed activities to prioritize work and available resources for equipment management. This paper describes the learning of highly…
High Temperature Hydrogen Attack (HTHA) is an insidious condition that can occur in process equipment exposed to hydrogen at elevated temperatures (at least 400F or 204C), under dry conditions, when…
Corrosion and Materials is a field of study that focuses on understanding the causes and mechanisms of corrosion. According to API 510…
Codes and Standards are the rules and regulations released by both governmental and non-government agencies in order to establish an agreed upon method of operation for conducting business. A proficient understanding of the codes and standards within each discipline is important…
On April 6, 2010, a tragic accident occurred at the Tesoro Refinery in Anacortes, WA, in the Naphtha Hydrotreater process unit (NHT). During routine operations involving an on-line switching of unit heat exchanger feed trains, seven employees were killed immediately, or died later of thermal burn injuries sustained when a feed-effluent heat exchanger catastrophically failed due to high temperature hydrogen attack (HTHA), releasing a hot, pressurized flammable hydrocarbon/hydrogen mixture which ignited. Tesoro released its investigative results to the media on September 01, 2010.
Rather than await the final report, the Northern and Southern California Process Safety Management district managers proactively initiated a California Emphasis Program (CEP) in April, 2010, under which Program Quality Verifications (PQV) were conducted in every California petroleum refinery to examine each refiner’s procedures and practices for identifying and mitigating corrosion damage known to be produced in the NHT process environment. The PQV focused on the NHT process units in general, and on NHT feed-effluent heat exchangers in particular. At the time the CEP began, the exact cause of the heat exchanger failure in Anacortes was yet unknown. What was known based on the documented historical experience of the refining industry, and published in its own technical literature is that the NHT operating environment can increase process equipment susceptibility to various forms of chloride corrosion and hydrogen attack.
The NHT process unit removes sulfur and nitrogen from straight run naphtha downstream of the Crude Distillation process unit (CDU). Removing these impurities involves treating the naphtha with hydrogen to create a suitable feed stock. The process poses operating and mechanical integrity challenges due to the presence of inorganic salts such as sodium chloride, magnesium chloride, and calcium chloride. Hydrogen is absorbed into metal, becomes trapped, and can cause embrittlement, cracking, and blisters.
While each refiner operates its NHT differently, consistent with defined business objectives, a feed-effluent heat exchanger nevertheless serves essentially the same purpose throughout the refining industry. Namely, to transfer the heat produced in a reactor pressure vessel to a feed stock. Typically, NHT feed-effluent exchangers are designed with consideration for potential sulfidation, high temperature H2/H2S corrosion, ammonium chloride corrosion, and high temperature hydrogen attack.
Additional corrosion phenomena found in the NHT include ammonium bisulfide and hydrochloric acid corrosion. Chlorides are difficult to control, and various types of aggressive corrosion phenomena present at varying operating temperatures and pressures downstream of the CDU.
Salt corrosion is caused by the hydrolysis of some metal chlorides to hydrogen chloride (HCI) and the subsequent formation of hydrochloric acid when crude is heated. Hydrogen chloride may also combine with ammonia used in chemical injection to form ammonium chloride (NH4CI), which causes fouling and corrosion.
Sulfur and nitrogen compounds are converted by a catalyst in the first stage reactor to hydrogen sulfide and ammonia. As the effluent stream from the reactor· cools down, the ammonia and hydrogen sulfide combine to form solid ammonium bisulfide (NH4HS) salts. Both concentrated NH4CI and NH4HS are highly corrosive to carbon steel and low alloys when wet. Dry, they are foulants that can inhibit heat transfer.
A comprehensive program for chlorides control should include monitoring of chloride levels in incoming crude in accordance with established acceptance criteria, effective desalting upstream of the CDU, effective water wash procedures and practices, effective chemical injection, appropriate materials selection and design, and rigorous monitoring.
Carbon and C-1/2 Mo steels in hydrogen service at temperatures above 450o F and pressures above 100 psia are susceptible to high temperature hydrogen attack (HTHA), a brittle fracture of a normally ductile material that occurs partially due to the corrosive effect of an environment. Under these operating parameters atomic and molecular hydrogen permeate the steel and react with dissolved carbides to form methane gas. The reaction decarburizes the steel, creating high localized stresses and resulting in voids and micro cracks that do not necessarily produce a tell-tale reduction in metal wall thickness.
Damage to welds, weld heat affected zones (HAZ), and/or base metal is undetectable· by conventional nondestructive examination methods during an incubation period during which time methane pressure builds in submicroscopic voids. HTHA is a long-term corrosion phenomenon that can be selective in location and degree of damage.
These corrosion phenomena are generally well understood, along with the mechanisms by which they degrade process equipment. Detection of each type of corrosion can be elusive given variability in process operating conditions, limitations in the monitoring equipment, and difficulty interpreting the data gathered.
The Northern and Southern California PSM district offices performed PQV compliance inspections in 11 refineries throughout California. On average, the NHTs had been in service from 25 to over 30 years. In every facility the metallurgy in its NHT(s) had been upgraded over time both in response to, then in anticipation of the effects of the types of corrosion discussed earlier.
The CEP focused on a review of each employer’s inspection, maintenance and operating procedures, practices, and experience specific to NHT feed-effluent heat exchangers. The Compliance personnel who conducted the inspections anticipated that these data collectively would chronicle equipment failures, near misses, and degradation. And that each facility’s historical record would reflect an evolving understanding of NHT corrosion phenomena and their control.
The inspectors expected to find documentation of the effects of hydrogen-induced damage, HTHA, and chloride corrosion in equipment whose metallurgy was vulnerable in an operating environment now processing sourer, higher acid crude slates, and more “opportunity crude”, which contains higher levels of contaminants and water. And they expected to find appropriate administrative, operational, and technical responses to the challenges presented. Such responses should include increased inspection, process changes, operating procedure modifications, and upgraded metallurgy. The costs of metallurgical upgrades are significant, and in some cases, facilities opted to modify process parameters and operating procedures in order to obviate “alloying up.”
Older process units used carbon steel, low chrome steels, 400 series stainless steel and non-stabilized 300 series stainless steel at temperatures higher than is considered safe today. In addition, these units used metallurgy such as C-1/2 Mo, which is now avoided as a result of industry experience. Operating limits for steels operating in a hydrogen environment are given in API Recommended Practice 941 Steels for Hydrogen Service at Elevated Temperatures and Pressure in Petroleum Refineries and Petrochemical Plants. The limits for C-1/2 Mo steels have been lowered twice because of unfavorable service experience; the first time in 1977.
After additional instances of HTHA occurred as much as 200o F below the revised 1977 Nelson Curve, the C- 1/2 Mo curve was removed altogether in 1990 and its specifications became identical to carbon steel. Equipment built before 1990 operating above the Carbon Steel Curve was suddenly at risk. New or replacement equipment base materials for heat exchanger shells and nozzles should be either 1.25 Cr-0.5 Mo or 2.25 Cr-0.5 Mo based on API 941 Nelson Curves. Cladding should be 300 series stainless steel, dependent on operating temperature and presence of hydrogen.
The CEP discovered that a common practice among at least some of the major oil refiners is to permit operation at 50o F above the Carbon Steel curve for C-1/2 Mo equipment. However, the equipment is prioritized for appropriate assessment, inspection and maintenance based on temperature, hydrogen partial pressure, operating time, thermal history of steel during fabrication, stress, cold work, age, and presence of cladding. California refiners recognize that cumulative operating time above the Nelson Curve increases equipment susceptibility to HTHA. While the equipment is in service at elevated temperature, the solubility of hydrogen in the Cr-Mo steels is higher, and the ductility of the material is greater, which prevents cracking phenomena. If temperatures are reduced at a rate which is too fast for diffusion, the diffusible hydrogen can localize at so-called trap sites such as dislocations, carbides, and non-metallic inclusions.
This can result in hydrogen “supersaturation” and hydrogen induced damage. The reduced ductility of the metal at the lower temperatures and the existence of applied, residual or thermal stresses may induce crack initiation. Such equipment must be inspected for HTHA using at least two inspection methods in combination. Base metal HTHA can be detected in its early stages using ultrasonic backscatter, velocity ratio, attenuation, and/or spectral analysis techniques. Use of ultrasonic shear wave inspection can reliably detect HTHA in welds only after cracks have formed. Higher frequencies can enhance detection capability.
The California Emphasis Program was initiated in response to a tragedy that, like most workplace injuries, likely could have been avoided. While it might be axiomatic that corrosion is inherent in the petroleum refining process, the direct costs of which approach $4 billion annually, the technology exists to manage its effects. The California refining industry collectively meets the challenges presented by corrosion phenomena known for decades to exist in the Naphtha Hydrotreating process.
Each Refiner has developed and implemented its own proprietary strategies for controlling the constellation of damage mechanisms common to the complexities of crude oil refining. All of these programs incorporate recognized and generally accepted good engineering practices for managing and reducing risk.
Hydrotreater
Hydrotreater
Also known as: hydrodesulfurization, HTU, HDS unit
The purpose of a hydrotreater unit is primarily to remove sulfur and other contaminants from intermediate streams before blending into a finished refined product or before being fed into another refinery process unit.
Hydrotreaters have become increasingly important as sulfur limits have been lowered in finished products. Also, for some key conversion units such as the reformer, feed must be hydrotreated to keep contaminants from poisoning the conversion catalyst.
Hydrotreaters also saturate aromatics and olefins if operated at high pressure, which is great for diesel quality (raises cetane) but bad for gasoline (reduces octane).
Types of hydrotreaters
It is quite common for a refinery to have multiple hydrotreaters. Some of the more common are:
How it works
The hydrocarbon is mixed with hydrogen and heated to 500-750F. The mixture is injected into a reactor vessel filled with a solid metal catalyst (cobalt-molybdenum or nickel-molybdenum).
In the presence of the catalyst and heat, the hydrogen reacts with the hydrocarbon, removing sulfur (to form H2S), removing nitrogen (to form ammonia), and saturating olefins and aromatics with hydrogen.
Typically, there is also a small amount of hydrocarbon cracking to form methane, ethane, propane, and butane.
The operating pressure of any hydrotreating unit is elevated to reduce the amount of coke laydown on the catalysts, which are normally in fixed beds. In general, the heavier the type of feedstock, the higher the operating pressure of the unit.
An Overview of Hydrotreating
Sections
Hydrotreating processes are becoming increasingly important as refineries work to meet more stringent environmental guidelines.
Most products of crude and vacuum distillation in refineries contain a significant amount of sulfur that must be removed prior to further processing or use. Hydrotreating or hydrodesulfurization refers to a set of operations that remove sulfur and other impurities (Figure 1). During hydrotreating, crude oil cuts are selectively reacted with hydrogen in the presence of a catalyst at relatively high temperatures and moderate pressures. The process converts undesirable aromatics, olefins, nitrogen, metals, and organosulfur compounds into stabilized products. Some hydrotreated cuts may require additional processing to meet final product specifications.
▲Figure 1. This general process flow diagram of a petroleum refinery includes several hydrotreating units.
This article explains the basics of hydrotreating processes, focusing on two of the most important petroleum products, naphtha and diesel oil. It describes how the hydrotreatment process differs between these two distillation cuts, and looks forward to what’s next in hydrotreatment as environmental standards for fuels become increasingly stringent.
Why is hydrotreatment necessary?
Petroleum refineries transform crude oil into useful fuels and products while satisfying technical, government, and safety requirements. In addition, they must comply with environmental policies that increasingly limit the amount of sulfur and other impurities in fuels. Hydrotreatment processes reduce the impurity content of petroleum products, which increases the efficiency of the fuels and reduces the production of harmful combustion byproducts such as NOx and SOx (Figure 2). Hydrotreatment also helps to satisfy final product specifications. Contaminants can affect the performance of downstream unit operations, catalysts, or even engines. One of the most common issues is nickel catalyst poisoning by sulfur, which is chemisorbed in catalytic beds.
▲Figure 2. Hydrotreating processes are standard in refineries primarily to remove sulfur from refined petroleum fuels. This helps reduce sulfur dioxide emissions that are formed when the fuels are combusted.
Hydrotreating (1) is an efficient method to remove several compounds, including:
Sulfur is the most critical compound to remove. It is present in nearly all crude oil feedstocks as sulfur mercaptans, sulfides, disulfides, polysulfides, and thiophenes.
Nitrogen is typically treated with hydrogen gas and transformed into ammonia gas.
Oxygen is reacted with hydrogen and eliminated as water. Most oxygen in distillation cuts is not present as oxygen gas, but bonded to hydrocarbons.
Olefins are volatile and unstable, and they are not desirable in fuels. Olefins are transformed into stable paraffinic hydrocarbons.
Metals are removed because they can deposit on catalysts and in engines.
The basics of hydrotreating
It is common to assume that the hydrotreating process is a single unit operation that converts all of the raw feed into a final desulfurized product. However, this is not the case; most hydrotreatment processes require many unit operations, including a reactor, gas separators, separation columns, and heat exchangers. The process can be divided into three main processing blocks:
heat exchange network
reactor in which the actual hydrotreating takes place
stripping where the desulfurized product stream is separated from the volatiles, gases, and impurities.
Each hydrotreating unit is tailored to the feedstock and end product. For instance, the process to hydrotreat naphtha is not the same as the process for diesel fuels. The most common cuts that are hydrotreated in a refinery include: light naphtha, heavy naphtha, jet fuel or kerosene, and diesel oils (e.g., light and heavy coker diesel oil). This article focuses on the two main cuts: naphtha and diesel oil.
The feed is first pressurized and mixed with the recycle and makeup hydrogen streams. The mixture is heated to about 290–430°C before entering the fixed-bed reactor, which operates at about 7–180 bar. Higher temperatures and pressures are used for processing heavier feedstocks, such as diesel oils. Overall, however, hydrotreater temperatures are relatively moderate, which avoids thermal cracking of molecules while being high enough to enable reaction of the feedstock.
Inside the fixed-bed reactor, hydrogenolysis and mild hydrocracking reactions take place to convert sulfur, nitrogen, oxygen, and other contaminants to hydrogen sulfide, ammonia, water vapor, and other stabilized byproducts (Figure 3). The catalyst used in the reactor is a crucial design consideration that greatly affects the final products. If sulfur removal is the primary goal, cobalt-molybdenum catalysts are favored. If the crude oil is relatively low in sulfur, nitrogen removal becomes the priority and nickel-molybdenum catalysts are chosen. Depending on the conditions and composition of the outlet streams, the byproducts are either discarded, recycled, or sent for further treatment.
▲Figure 3. Common hydrotreating unit reactions convert impurities to stabilized products in the presence of excess hydrogen (1).
Most outlet streams undergo further treatment to lessen their environmental impact and/or recover the material for use. Sour gas (which contains hydrocarbons, carbon dioxide, and a significant amount of hydrogen sulfide) is commonly sent to an amine gas treating unit that separates the hydrocarbon gases from the hydrogen sulfide and carbon dioxide. During amine treatment, the carbon dioxide and hydrogen sulfide are absorbed by an amine solution in the absorption unit, producing a sweet gas and amine-rich stream. The amine-rich mixture is pumped to a desorption unit where it is recovered as lean amine and recycled (Figure 4). The final product stream is a desulfurized product fuel, commonly called sweet gas.
▲Figure 4. The amine gas treatment process includes an absorption unit that removes contaminants and produces a sweet gas stream and a stipping unit that recycles the amine solution.
The importance of hydrogen
Hydrogen gas is one of the most important elements in the production of desulfurized fuels. For hydrotreating, the hydrogen stream must be extremely pure (>99%) and have no humidity. The stream should have a low hydrocarbon content, as well as low mercaptan and hydrogen sulfide levels (<0.1%). Only about 15–30% of the hydrogen demand of a refinery is produced internally by processes such as catalytic reforming of naphtha; the rest is supplied by external producers (2). The industry uses a variety of terms for hydrogen that depend on how it was produced: Brown hydrogen is obtained from fossil fuels such as coal or lignite via gasification. Gasification has a large carbon footprint, but remains a common way to produce hydrogen. Gray hydrogen is obtained from natural gas via steam-methane reforming, and has a smaller carbon footprint than brown hydrogen. It has become the most common type of hydrogen due to low prices for natural gas. Blue hydrogen is commonly produced from methane, but differs from gray hydrogen in that the resulting carbon emissions are captured and sequestered. Due to environmental restrictions, blue hydrogen is becoming more common. Turquoise hydrogen is produced from a feedstock of pure methane via pyrolysis. It is associated with a very small carbon footprint, because pyrolysis byproducts include only solid carbon and no carbon dioxide. Green hydrogen is produced from any renewable energy source, such as electrolysis of water via windmills or solar energy. It has not gained traction due to technology challenges and high prices. Hydrotreating naphtha Naphtha is a valuable product of petroleum refining, as it is one of the main constituents of the gasoline blending pool. While there is no formal definition of naphtha, it is commonly considered the C5–C12 cut, which is divided into light and heavy naphtha. Light naphtha has an initial boiling point (IBP) of about 30°C and a final boiling point (FBP) of about 145°C. It contains most of the hydrocarbons between C4 and C6. Heavy naphtha has an IBP and FBP of about 140°C and 205°C, respectively. It contains most of the hydrocarbons in the C6–C12 range. High sulfur content is associated with cuts that are heavier than naphtha. However, removing the relatively small amount of sulfur in naphtha is beneficial for engine performance and operational longevity. Figure 5 presents a flow diagram of the hydrotreating process for naphtha (3). ▲Figure 5. This flow diagram shows the hydrotreating process for naphtha. Heating. The naphtha feed enters the hydrotreatment unit through a charge pump. It is first mixed with hydrogen gas from either the catalytic reforming unit (CRU) or refinery hydrogen plant. The mixture is then heated to 340°C while being contacted with the reactor’s effluent. The charge heater has four passes with four gas burners. Heater tubes are constructed of Type 321 stainless steel, which is the grade of choice for applications with temperatures up to around 900°C, because it combines high strength and resistance to scaling with resistance to aqueous corrosion. Reaction. After preheating, the mixture is fed to a reactor with two catalyst beds. The desulfurization reactions take place over the cobalt-molybdenum bed and the nitrogen reactions take place over the alumina bed. The reactor temperature is held at a constant 315°C and a pressure of 370 psig. The reactor effluent contains mostly the desulfurized naphtha, excess hydrogen, hydrogen sulfide, ammonia, and light hydrocarbons (C1–C4) due to mild cracking. The reactor effluent is cooled and partially condensed through a feed/effluent heat exchanger and then cooled with air. Separations. The separation process, or stripping section, uses a series of separators and columns to stabilize the naphtha. The cooled stream from the reactor is sent to a pressurized flash separator at 290 psig. The light ends, mainly hydrogen sulfide, ammonia, excess hydrogen gas, and light hydrocarbons, are separated from the bulk of the desulfurized naphtha. The liquid naphtha stream from the separator is then sent to the stripping unit. The stripping column is heated to 340°C by a reboiler and held at a pressure of 205 psig. High temperature and pressure enable removal of volatile material (light hydrocarbons), which would vaporize at final storage and use conditions. Inlets to the stripping column include desulfurized raw naphtha, recycled desulfurized stripped naphtha, and the bottoms of the column. The outlet streams include mostly light gases (C1–C5 hydrocarbons) that are sent for amine treatment to recover them as fuels. The resulting liquid naphtha is then cooled by air and sent out of the unit’s battery limits as stabilized hydrotreated naphtha product. Hydrotreating diesel oils Diesel oil may be either a direct cut from the atmospheric distillation column or a mixture of light cycle oil from the fluid catalytic cracker (FCC) unit and heavy cycle oil from the delayed coker. These cuts contain 1–2% sulfur (10,000–20,000 ppm) — much higher than the fuel requirement of 10–15 ppm. Therefore, hydrotreating is one of the most important steps of processing diesel oils to specification, as it removes sulfur and other impurities such as nitrogen and olefins. In addition, hydrotreating saturates olefins (removal of double-bonded carbons) within the diesel oil. This process increases the stability and decreases volatility of the diesel, enabling longer storage. The process of hydrotreating diesel oil cuts is much more complex than that of naphtha, primarily due to the addition of the regenerative amine system, which recovers excess hydrogen gas and removes hydrogen sulfide via diethanolamine (DEA). Figure 6 presents a flow diagram of the hydrotreating process for diesel oil. ▲Figure 6. This flow diagram shows the hydrotreating process for diesel oil. Heating. The raw untreated diesel oil is pumped directly to the heat exchange network. Hydrotreating processes are designed with heat exchange networks that pair the low-temperature feed to the reactor, which requires heating, to the high-temperature reactor effluent that requires cooling. Reaction. The heated feedstock is mixed with a hot recycle hydrogen stream recovered from downstream processes, and the mixture is sent to the reactor. Depending on the sulfur content of the stream, either a cobalt-molybdenum bed (sulfur removal) or nickel-molybdenum on alumina bed (nitrogen removal) will be used. Because high-sulfur fuels are more common in the industry today, sulfur removal is typically the focus of diesel oil hydrotreating. The effluent of the reactor includes the offgases to be removed in the separator, light ends that will be treated and sent to the naphtha unit, and the unstabilized diesel oils. Separations. The reactor effluent is cooled in the heat exchange network, and fresh liquid condensate from lighter cuts of the crude distillation unit is injected into the reactor effluent to avoid salt formation in downstream unit operations. The mixture is then flashed into a high-pressure separator drum, producing a liquid byproduct ammonia solution that is sent to the refinery wastewater system and a hydrogen-rich gas that contains some hydrogen sulfide. The gases are sent to an absorber that removes the hydrogen sulfide via a circulating DEA solution. The resulting hydrogen stream is combined with makeup hydrogen and is injected into the feedstock stream that enters the initial hydrotreatment reactor. The now-stabilized diesel oil from the flash drum is depressurized in a successive flash drum. The process of depressurization favors gas formation, further stabilizing the liquid hydrocarbons. The flash gas is sent for hydrogen sulfide removal before going to the refinery’s fuel system. The bottoms liquid stream from the second flash drum is preheated and sent to a stabilizer column. The stabilizer column produces three main cuts: the naphtha gas to be recovered, the recovered naphtha to be combined with other naphtha streams, and the desulfurized stabilized diesel. Challenges and the future of hydrotreating Hydrotreating is critical to addressing challenges refineries are facing today. Fuel consumption worldwide is increasing, putting pressure on refiners to increase production. Additionally, low-sulfur crude oils are becoming scarce, forcing refiners to contend with high-sulfur feedstocks while meeting increasingly tighter restrictions on sulfur concentrations in fuels. Addressing this compound challenge requires the development and application of catalyst technologies that improve reaction rates, conversion, and overall performance of hydrotreating processes. Current catalysts suffer from selectivity issues that could be overcome by alternative technologies such as titanium dioxide and zirconium dioxide catalysts. Another factor to consider is the hydrogen gas requirements of hydrotreating processes. Refineries typically operate at a hydrogen deficit, requiring purchase of hydrogen from outside vendors. As environmental restrictions become tighter, refiners will need to explore hydrogen sources with small carbon footprints. Literature Cited Fahim, M., et al., “Fundamentals of Petroleum Refining,” Elsevier Science, Amsterdam, Netherlands (2010). U.S. Energy Information Administration, “EIA-820 Annual Refinery Report,” EIA, Washington, DC (2021). Rao, B., “Modern Petroleum Refining Processes, 6th Edition,” CBS Publishers and Distributors Private Limited, New Delhi, India (2018).
An Overview of Hydrotreating
Sections
Hydrotreating processes are becoming increasingly important as refineries work to meet more stringent environmental guidelines.
Most products of crude and vacuum distillation in refineries contain a significant amount of sulfur that must be removed prior to further processing or use. Hydrotreating or hydrodesulfurization refers to a set of operations that remove sulfur and other impurities (Figure 1). During hydrotreating, crude oil cuts are selectively reacted with hydrogen in the presence of a catalyst at relatively high temperatures and moderate pressures. The process converts undesirable aromatics, olefins, nitrogen, metals, and organosulfur compounds into stabilized products. Some hydrotreated cuts may require additional processing to meet final product specifications.
▲Figure 1. This general process flow diagram of a petroleum refinery includes several hydrotreating units.
This article explains the basics of hydrotreating processes, focusing on two of the most important petroleum products, naphtha and diesel oil. It describes how the hydrotreatment process differs between these two distillation cuts, and looks forward to what’s next in hydrotreatment as environmental standards for fuels become increasingly stringent.
Why is hydrotreatment necessary?
Petroleum refineries transform crude oil into useful fuels and products while satisfying technical, government, and safety requirements. In addition, they must comply with environmental policies that increasingly limit the amount of sulfur and other impurities in fuels. Hydrotreatment processes reduce the impurity content of petroleum products, which increases the efficiency of the fuels and reduces the production of harmful combustion byproducts such as NOx and SOx (Figure 2). Hydrotreatment also helps to satisfy final product specifications. Contaminants can affect the performance of downstream unit operations, catalysts, or even engines. One of the most common issues is nickel catalyst poisoning by sulfur, which is chemisorbed in catalytic beds.
▲Figure 2. Hydrotreating processes are standard in refineries primarily to remove sulfur from refined petroleum fuels. This helps reduce sulfur dioxide emissions that are formed when the fuels are combusted.
Hydrotreating (1) is an efficient method to remove several compounds, including:
Sulfur is the most critical compound to remove. It is present in nearly all crude oil feedstocks as sulfur mercaptans, sulfides, disulfides, polysulfides, and thiophenes.
Nitrogen is typically treated with hydrogen gas and transformed into ammonia gas.
Oxygen is reacted with hydrogen and eliminated as water. Most oxygen in distillation cuts is not present as oxygen gas, but bonded to hydrocarbons.
Olefins are volatile and unstable, and they are not desirable in fuels. Olefins are transformed into stable paraffinic hydrocarbons.
Metals are removed because they can deposit on catalysts and in engines.
The basics of hydrotreating
It is common to assume that the hydrotreating process is a single unit operation that converts all of the raw feed into a final desulfurized product. However, this is not the case; most hydrotreatment processes require many unit operations, including a reactor, gas separators, separation columns, and heat exchangers. The process can be divided into three main processing blocks:
heat exchange network
reactor in which the actual hydrotreating takes place
stripping where the desulfurized product stream is separated from the volatiles, gases, and impurities.
Each hydrotreating unit is tailored to the feedstock and end product. For instance, the process to hydrotreat naphtha is not the same as the process for diesel fuels. The most common cuts that are hydrotreated in a refinery include: light naphtha, heavy naphtha, jet fuel or kerosene, and diesel oils (e.g., light and heavy coker diesel oil). This article focuses on the two main cuts: naphtha and diesel oil.
The feed is first pressurized and mixed with the recycle and makeup hydrogen streams. The mixture is heated to about 290–430°C before entering the fixed-bed reactor, which operates at about 7–180 bar. Higher temperatures and pressures are used for processing heavier feedstocks, such as diesel oils. Overall, however, hydrotreater temperatures are relatively moderate, which avoids thermal cracking of molecules while being high enough to enable reaction of the feedstock.
Inside the fixed-bed reactor, hydrogenolysis and mild hydrocracking reactions take place to convert sulfur, nitrogen, oxygen, and other contaminants to hydrogen sulfide, ammonia, water vapor, and other stabilized byproducts (Figure 3). The catalyst used in the reactor is a crucial design consideration that greatly affects the final products. If sulfur removal is the primary goal, cobalt-molybdenum catalysts are favored. If the crude oil is relatively low in sulfur, nitrogen removal becomes the priority and nickel-molybdenum catalysts are chosen. Depending on the conditions and composition of the outlet streams, the byproducts are either discarded, recycled, or sent for further treatment.
▲Figure 3. Common hydrotreating unit reactions convert impurities to stabilized products in the presence of excess hydrogen (1).
Most outlet streams undergo further treatment to lessen their environmental impact and/or recover the material for use. Sour gas (which contains hydrocarbons, carbon dioxide, and a significant amount of hydrogen sulfide) is commonly sent to an amine gas treating unit that separates the hydrocarbon gases from the hydrogen sulfide and carbon dioxide. During amine treatment, the carbon dioxide and hydrogen sulfide are absorbed by an amine solution in the absorption unit, producing a sweet gas and amine-rich stream. The amine-rich mixture is pumped to a desorption unit where it is recovered as lean amine and recycled (Figure 4). The final product stream is a desulfurized product fuel, commonly called sweet gas.
▲Figure 4. The amine gas treatment process includes an absorption unit that removes contaminants and produces a sweet gas stream and a stipping unit that recycles the amine solution.
The importance of hydrogen
Hydrogen gas is one of the most important elements in the production of desulfurized fuels. For hydrotreating, the hydrogen stream must be extremely pure (>99%) and have no humidity. The stream should have a low hydrocarbon content, as well as low mercaptan and hydrogen sulfide levels (<0.1%). Only about 15–30% of the hydrogen demand of a refinery is produced internally by processes such as catalytic reforming of naphtha; the rest is supplied by external producers (2). The industry uses a variety of terms for hydrogen that depend on how it was produced: Brown hydrogen is obtained from fossil fuels such as coal or lignite via gasification. Gasification has a large carbon footprint, but remains a common way to produce hydrogen. Gray hydrogen is obtained from natural gas via steam-methane reforming, and has a smaller carbon footprint than brown hydrogen. It has become the most common type of hydrogen due to low prices for natural gas. Blue hydrogen is commonly produced from methane, but differs from gray hydrogen in that the resulting carbon emissions are captured and sequestered. Due to environmental restrictions, blue hydrogen is becoming more common. Turquoise hydrogen is produced from a feedstock of pure methane via pyrolysis. It is associated with a very small carbon footprint, because pyrolysis byproducts include only solid carbon and no carbon dioxide. Green hydrogen is produced from any renewable energy source, such as electrolysis of water via windmills or solar energy. It has not gained traction due to technology challenges and high prices. Hydrotreating naphtha Naphtha is a valuable product of petroleum refining, as it is one of the main constituents of the gasoline blending pool. While there is no formal definition of naphtha, it is commonly considered the C5–C12 cut, which is divided into light and heavy naphtha. Light naphtha has an initial boiling point (IBP) of about 30°C and a final boiling point (FBP) of about 145°C. It contains most of the hydrocarbons between C4 and C6. Heavy naphtha has an IBP and FBP of about 140°C and 205°C, respectively. It contains most of the hydrocarbons in the C6–C12 range. High sulfur content is associated with cuts that are heavier than naphtha. However, removing the relatively small amount of sulfur in naphtha is beneficial for engine performance and operational longevity. Figure 5 presents a flow diagram of the hydrotreating process for naphtha (3). ▲Figure 5. This flow diagram shows the hydrotreating process for naphtha. Heating. The naphtha feed enters the hydrotreatment unit through a charge pump. It is first mixed with hydrogen gas from either the catalytic reforming unit (CRU) or refinery hydrogen plant. The mixture is then heated to 340°C while being contacted with the reactor’s effluent. The charge heater has four passes with four gas burners. Heater tubes are constructed of Type 321 stainless steel, which is the grade of choice for applications with temperatures up to around 900°C, because it combines high strength and resistance to scaling with resistance to aqueous corrosion. Reaction. After preheating, the mixture is fed to a reactor with two catalyst beds. The desulfurization reactions take place over the cobalt-molybdenum bed and the nitrogen reactions take place over the alumina bed. The reactor temperature is held at a constant 315°C and a pressure of 370 psig. The reactor effluent contains mostly the desulfurized naphtha, excess hydrogen, hydrogen sulfide, ammonia, and light hydrocarbons (C1–C4) due to mild cracking. The reactor effluent is cooled and partially condensed through a feed/effluent heat exchanger and then cooled with air. Separations. The separation process, or stripping section, uses a series of separators and columns to stabilize the naphtha. The cooled stream from the reactor is sent to a pressurized flash separator at 290 psig. The light ends, mainly hydrogen sulfide, ammonia, excess hydrogen gas, and light hydrocarbons, are separated from the bulk of the desulfurized naphtha. The liquid naphtha stream from the separator is then sent to the stripping unit. The stripping column is heated to 340°C by a reboiler and held at a pressure of 205 psig. High temperature and pressure enable removal of volatile material (light hydrocarbons), which would vaporize at final storage and use conditions. Inlets to the stripping column include desulfurized raw naphtha, recycled desulfurized stripped naphtha, and the bottoms of the column. The outlet streams include mostly light gases (C1–C5 hydrocarbons) that are sent for amine treatment to recover them as fuels. The resulting liquid naphtha is then cooled by air and sent out of the unit’s battery limits as stabilized hydrotreated naphtha product. Hydrotreating diesel oils Diesel oil may be either a direct cut from the atmospheric distillation column or a mixture of light cycle oil from the fluid catalytic cracker (FCC) unit and heavy cycle oil from the delayed coker. These cuts contain 1–2% sulfur (10,000–20,000 ppm) — much higher than the fuel requirement of 10–15 ppm. Therefore, hydrotreating is one of the most important steps of processing diesel oils to specification, as it removes sulfur and other impurities such as nitrogen and olefins. In addition, hydrotreating saturates olefins (removal of double-bonded carbons) within the diesel oil. This process increases the stability and decreases volatility of the diesel, enabling longer storage. The process of hydrotreating diesel oil cuts is much more complex than that of naphtha, primarily due to the addition of the regenerative amine system, which recovers excess hydrogen gas and removes hydrogen sulfide via diethanolamine (DEA). Figure 6 presents a flow diagram of the hydrotreating process for diesel oil. ▲Figure 6. This flow diagram shows the hydrotreating process for diesel oil. Heating. The raw untreated diesel oil is pumped directly to the heat exchange network. Hydrotreating processes are designed with heat exchange networks that pair the low-temperature feed to the reactor, which requires heating, to the high-temperature reactor effluent that requires cooling. Reaction. The heated feedstock is mixed with a hot recycle hydrogen stream recovered from downstream processes, and the mixture is sent to the reactor. Depending on the sulfur content of the stream, either a cobalt-molybdenum bed (sulfur removal) or nickel-molybdenum on alumina bed (nitrogen removal) will be used. Because high-sulfur fuels are more common in the industry today, sulfur removal is typically the focus of diesel oil hydrotreating. The effluent of the reactor includes the offgases to be removed in the separator, light ends that will be treated and sent to the naphtha unit, and the unstabilized diesel oils. Separations. The reactor effluent is cooled in the heat exchange network, and fresh liquid condensate from lighter cuts of the crude distillation unit is injected into the reactor effluent to avoid salt formation in downstream unit operations. The mixture is then flashed into a high-pressure separator drum, producing a liquid byproduct ammonia solution that is sent to the refinery wastewater system and a hydrogen-rich gas that contains some hydrogen sulfide. The gases are sent to an absorber that removes the hydrogen sulfide via a circulating DEA solution. The resulting hydrogen stream is combined with makeup hydrogen and is injected into the feedstock stream that enters the initial hydrotreatment reactor. The now-stabilized diesel oil from the flash drum is depressurized in a successive flash drum. The process of depressurization favors gas formation, further stabilizing the liquid hydrocarbons. The flash gas is sent for hydrogen sulfide removal before going to the refinery’s fuel system. The bottoms liquid stream from the second flash drum is preheated and sent to a stabilizer column. The stabilizer column produces three main cuts: the naphtha gas to be recovered, the recovered naphtha to be combined with other naphtha streams, and the desulfurized stabilized diesel. Challenges and the future of hydrotreating Hydrotreating is critical to addressing challenges refineries are facing today. Fuel consumption worldwide is increasing, putting pressure on refiners to increase production. Additionally, low-sulfur crude oils are becoming scarce, forcing refiners to contend with high-sulfur feedstocks while meeting increasingly tighter restrictions on sulfur concentrations in fuels. Addressing this compound challenge requires the development and application of catalyst technologies that improve reaction rates, conversion, and overall performance of hydrotreating processes. Current catalysts suffer from selectivity issues that could be overcome by alternative technologies such as titanium dioxide and zirconium dioxide catalysts. Another factor to consider is the hydrogen gas requirements of hydrotreating processes. Refineries typically operate at a hydrogen deficit, requiring purchase of hydrogen from outside vendors. As environmental restrictions become tighter, refiners will need to explore hydrogen sources with small carbon footprints. Literature Cited Fahim, M., et al., “Fundamentals of Petroleum Refining,” Elsevier Science, Amsterdam, Netherlands (2010). U.S. Energy Information Administration, “EIA-820 Annual Refinery Report,” EIA, Washington, DC (2021). Rao, B., “Modern Petroleum Refining Processes, 6th Edition,” CBS Publishers and Distributors Private Limited, New Delhi, India (2018).
Hydrotreating | Naphtha hydrotreating
High demands to get more value out of heavier feedstocks present new challenges for catalysts and technology. To name just one example, increasing use of coker material has led to higher silica and nitrogen levels in the naphtha feed pool, requiring catalysts with superior hydrodenitrogenation (HDN) activity and greater surface areas for maximum silicon uptake. Further downstream, naphtha pretreatment presents its own challenges, as the catalysts used in isomerization, catalytic reforming, and other units are extremely sensitive to impurities, such as sulfur, nitrogen, chloride, silicon and arsenic.
Our extensive range of naphtha hydrotreating catalysts and technologies are designed to handle all feedstocks and still ensure easy, reliable, stable, and profitable hydroprocessing. Superior process designs, high-performance catalysts, and proprietary equipment ensure significantly longer cycle length while increasing plant availability.
Furthermore, Topsoe offers related solutions for downstream petrochemicals processing, such as selective hydrogenation or benzene conversion.
Naphtha hydrotreater
Naphtha hydrotreater
Temperature measurement
The naphtha cut from the atmospheric distillation unit is sent to the naphtha hydrotreater to remove sulfur and nitrogen compounds. The naphtha hydro treating unit uses a cobalt-molybdenum catalyst to remove sulfur by converting it to hydrogen sulfide that is removed along with unreacted hydrogen. Reactor conditions for a naphtha hydrotreater unit are around 400-500˚F (205-260˚C) with a pressure of 350-650 psi (25-45 bar).
A two-wire style HART pressure transmitter is used to control the hydrotreater pressure. This application requires intrinsically safe signal measurement and SIL 2 with full assessment. The PR 9106B HART transparent repeater is connected to the pressure transmitter to bring the signal into the safe area. The output from the 9106B is connected to a control system and the HART information from the pressure transmitter passes through the 9106B for diagnostic purposes.
Application:
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Naphtha hydrotreater
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Debottleneck naphtha hydrotreaters with highest project ROI | Alfa Laval
We can say that naphtha hydrotreater is a bridge between the atmospheric distillation unit and downstream gasoline conversion processes. A bottleneck in the NHT could undermine the refiner’s capability to maximize gasoline production. Some of the NHT de-bottlenecking projects we’ve supported in recent years have common themes; their drivers and challenges are summarized in the following chart:
Capacity in existing process units is often limited by either reactor heater or recycle compressor capacity. Designing the process with maximum energy recovery at a lower circuit pressure drop in the combined feed/effluent exchanger, offloads the heater and the compressor, enabling the increase in unit capacity. With Alfa Laval Compabloc heat exchangers in your NHT combined feed/effluent exchanger services, you can lower capex and decrease your footprint and lead time without having to invest more in the capacity of your fired heater or compressor. Projects implementing Compabloc solution in NHT have significantly improved a project’s ROI and it’s rapidly becoming a norm for industry leaders.
In one of our recent NHT debottlenecking projects for a US Mid-West Refinery using a Compabloc solution, their plant engineers were able to increase capacity by 40% at a fraction of earlier project estimates which were based on a conventional design solution. This refinery was changing their crude slate to add more light crude and thereby increasing the load on their NHT unit. During the feasibility study, they found the reactor heater was limited in capacity and needed replacement—a capital-intensive solution also involving emission permit reapprovals. Another idea to avoid investing in a higher capacity heater was to increase heat recovery in combined feed to effluent heat exchanger before the heater. However, they found it was not economically and practically feasible (plot space limited) as it would require 14 shell and tube delivering 13F internal pinch to coverup for existing heater capacity limits.
However, having learned from the success of their gulf coast sister refinery which had implemented Compabloc technology in a similar NHT debottlenecking project, they contacted Alfa Laval to optimize a Compabloc solution. With the right CFE design skills, process and application know how and operational experience, Alfa Laval proposed a Compabloc solution with just two units capable of delivering the required 13F pinch at a fraction of previous project estimates and in a much smaller footprint. The table below gives a summary of the driver, challenges and solution:
To gain more in-depth knowledge on how to implement Compabloc technology in NHT, we recommend tuning into our technical webinar, “Improving hydrotreater performance using welded plate heat exchanger,” and reading our technical articles below.
Click here for more information or contact an Alfa Laval refinery expert today.
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