Visbreaking Process

Visbreaking is a non-catalytic thermal process that converts atmospheric or vacuum residues via  thermal cracking to gas, naphtha, distillates, and visbroken residue. Atmospheric and vacuum residues are typically charged to a visbreaker to reduce fuel oil viscosity and increase distillate yield in the refinery.

Advantages of the Foster Wheeler/UOP visbreaking process are:

• High sulfur fuel oil reduction
• Reduces distillate cutter stock requirements, making the distillate available for more valuable transportation distillate fuels
• Low cost upgrading ($900 / BPSD US Gulf Coast basis)

There are two types of visbreaking technology that are commercially available: the ‘coil’ or ‘furnace’ type and the ‘soaker’ process. In the coil process, conversion is achieved by high temperature cracking for a predetermined, relatively short period of time in the heater. In the soaker process, which is a low temperature/high residence time process, the majority of conversion occurs in a reaction vessel or soaker drum, where the two-phase heater effluent is held at a lower temperature for a longer period of time.

Foster Wheeler has utilized both soaking coil and soaking drum technologies in the design of visbreakers and thermal crackers. A number of the units designed by Foster Wheeler have integrated visbreaking and thermal cracking sections.

In a ‘coil’ type operation, charge is fed to the visbreaker heater where it is heated to a high temperature, causing partial vaporization and mild cracking. The heater outlet stream is quenched with gas oil or fractionator bottoms to stop the cracking reaction. The vapor-liquid mixture enters the fractionator to be separated into gas, naphtha, gas oil and visbroken resid (tar). The visbroken bottoms are then blended with lighter materials (cutter stock) to meet fuel oil specifications. The fractionated visbreaker gas oil is often used as the cutter stock.

Visbreakers can be configured with vacuum flashers on the tar stream to produce more heavy gas oil distillate and can also be configured as two-stage visbreaker/thermal cracker for maximum yield of lighter distillates.

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Flue Gas Treatment

Treating flue gas minimizes or eliminates both the environmentally unacceptable nitrogen oxide (NOx) and sulfur dioxide (SO2) emissions as well as the collecting of unburned solid particles before they escape into the atmosphere. Both techniques involve a number of steps

NOx Reduction Techniques

Fuel Selection

Control of NOx pollutants begins with the proper fuel selection. A coal with a sufficiently low fuel nitrogen (less than 1.5%) as shown in a routine fuel analysis may eliminate the need for any NOx reduction techniques. Natural gas has no nitrogen in the fuel; fuel oil typically has a lower nitrogen content than coal. Coal reactivity may also be decreased to slow down combustion and decrease temperatures to minimize NOx production. Lower flame temperatures will result in a lower level of NOx production in oil and gas-fired systems. Boiler systems that have highly turbulent flames and high temperature furnaces usually need lower fuel nitrogen than is normally available in the required quantities. Reduction techniques would then be needed.

Furnace Sizing

This step is only practical if a new facility is planned. By increasing the furnace cooling surface, the high temperature and time aspects of NOx production can be reduced. Another benefit is the increased flexibility in coal purchasing especially in specifications and price.

Burner Selection

Selecting a burner relative to furnace size limits the oxygen availability to form NOx while simultaneously shaping the flame to minimize the 2800 degree residency time. This permits the use of moderate and low-nitrogen coal and meeting NOx emission regulations. This method generally produces good results.

Low Excess Air Combustion

This technique also limits the availability of oxygen and increases the efficiency of a high-turbulence burner. There is little change in the 2800-degree residency time and only fair results can be expected. Also, when this technique is used, a fairly complex series of controls must be installed to maintain the best combustion. Coal ash problems may also arise due to the reduced oxygen levels.

Two-Stage Firing

This technique also limits oxygen availability by adding excess oxygen, needed for complete combustion, through overfire air ports. The rate of combustion is lessened and the 2800 degree residency time is decreased. It produces good results with moderate-to-high fuel nitrogen coals. There is the possibility of decreased carbon burnout and furnace heat absorption and an increase in fireside deposits and potential corrosion.

Off-Stoichiometric Firing

This method also limits oxygen availability and flame temperature but for different levels of burners on large units. It is fairly successful and easily applied to existing units. As in the two-stage firing technique, there can be carbon loss and increased slagging.

Flue Gas Recirculation

This method takes advantage of the reaction that tends to drive fuel nitrogen towards N2 in the presence of NO. With NO present, there is a tendency to minimize the formation of thermal NOx by driving the reaction toward the more stable N2. This is a “last resort” technique when regulations must be met with high-nitrogen coal. It is the most effective method but it is the most expensive and difficult to install. Combustion control equipment and operating requirements with fans, ductwork and air balancing increase the complexity and can create problems.

Selective Non-Catalytic Reduction (SNCR) and Selective Catalytic Reduction (SCR)

There are two types of SNCR control technologies for retrofit to industrial boilers; one uses ammonia as the reducing agent; the other urea.

They reduce NOx in the flue gas to molecular hydrogen at high temperatures between 1600 and 2000 degrees Fahrenheit without a catalyst. With a catalyst the conversion takes place at a much lower temperature range, roughly 575-800 degrees Fahrenheit. This is called SCR. Typically these agents are injected in the post-combustion region.

Because of the significant load variations in industrial boilers which cause the optimum temperature zone to shift location in the boiler, the application and effectiveness of this type of flue gas treatment is limited.

Solid Particle Removal

The removal of solid particles from the flue gas (also called particulate emissions) is an important part of the combustion process, as proper system selection and the maintenance of that system can significantly affect plant operating costs, as well as legislative compliance. These solid particles are basically the nonburnable elements in coal that leave the furnace and boiler after combustion.

There are a number of control techniques that can be applied, varying with the type of coal and combustion equipment installed (stoker, fluidized-bed or pulverized-coal firing):

Mechanical Collection

This is the oldest form of particulate collection. It extracts ash particles from the flue gas circular air current, which forces the particles to the outer portion of the current and downward into a storage hopper. It is typically found in stoker-fired boilers. Some spreader stoker fired boilers use mechanical collectors ahead of precipitators or baghouses for reinjection of the flycarbon and for an increase in overall collection efficiency.

Sidestream Separation

This is an additional technique applied to mechanical collection to improve collection efficiency. In operation, some 10-20% of the flue gas is removed from the bottom hopper of the collector and cleaned in a small baghouse. This can in-crease ash collection efficiency by up to 35-50%.

Electrostatic Precipitators

These devises operate on the principle that the ash particles can accept an electrical charge. Particles pass through an electrical field and are attracted to a vertical metal plate, where, periodically, they are shaken loose and collected in the collection hopper.

Baghouse Collectors

These systems, quite simply, work on the same principle as a household or industrial bag-type vacuum cleaner. The ash is removed in one of two ways; a reverse stream of air is blown through the bag during collection shutdown, which re-moves the ash coating and channels it into a collection hopper. The other method involves collection of the ash on the outside of the bag. A high-pressure pulse of air is periodically forced down through the bag, shaking the ash from the bag and into the ash hopper.

Wet Scrubbers

These devises cause the ash to be mixed with water droplets in a high-velocity air stream. The ash-laden droplets are then collected in a down-stream scrubber demister section. Care must be taken in the disposal of the contaminated water, which will contain sulfuric and hydrochloric acid from the chemical combination of water and fly-ash. Also, additional care must be taken to assure the water is properly and completely removed from the flue gas. A wet scrubber has an advantage since additional heat is removed from the flue gas and can be recovered by exchangers for heating makeup water For comparison purposes, here are the cost differentiation factors between the various solid particulate collection systems, starting with the assumption that the mechanical collector is a factor of one:

Sulfur Dioxide Removal and Control

All coal and oil contain some sulfur. As a result, there is bound to be some amount of sulfur dioxide generated in the combustion process. Just how its emission is minimized depends on a number of available techniques.

Coal Benefication

Using washed coal is considered the best alternative for meeting sulfur regulations. Factors such as transportation, availability and price need to be considered. This practice is not as common as it used to be, given the availability of lower-sulfur coal.

Wet Nonregenerative Scrubbers

These systems can operate in a “throwaway” mode, where the sulfur dioxide gas reacts with a chemical, such as limestone, and the combined compound is disposed of or sold for gypsum. With additional processing, the elemental sulfur can be separated and made available for sale. Solids and pH levels are continuously monitored from a slipstream takeoff.

Wet Regenerative System

These scrubbers substantially speed up the collection process. However, their effectiveness requires the use of expensive sodium hydroxide or sodium carbonate, which require recovery systems. A major benefit, however, is the lack of sol-ids buildup, scaling, or critical pH control.

Dry Scrubbers

Here the flue gas is combined with chemicals in a water-based spray. The heat in the flue gas dries up the moisture, leaving a solid product, collectable in the baghouse. Critical elements in these systems include residence time in the chamber, flue gas temperature, which must be high enough to assure 100% moisture evaporation and adequate mixing of the chemical with the flue gas.

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Bernoulli’s Theorem

The Bernoulli Theorem1 is a mathematical derivation based on the law of conservation of energy. This theorem states that the total energy of a fluid at any particular point above a datum plane is the sum of the elevation head, the pressure head, and the velocity head. Stated mathematically:

    Eq. (1)

If there are no friction losses and no energy is added to or taken from the system, H is constant for any point in the fluid. In reality, whenever fluid is moving there is friction loss (h_L). This loss describes the difference in total energy at two points in the system. Expressing the energy levels at Point 1 versus Point 2 then becomes:

 Eq. (2)

All practical formulas for fluid flow are derived from the above. Modifications to Eq (2) have been proposed by many investigators to account for the friction losses.

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Benefits of Biodiesel

Environmental Benefits

In 2000, biodiesel became the only alternative fuel in the country to have successfully completed the EPA-required Tier I and Tier II health effects testing under the Clean Air Act.  These independent tests conclusively demonstrated biodiesel’s significant reduction of virtually all regulated emissions, and showed biodiesel does not pose a threat to human health. 

Biodiesel contains virtually no sulfur or aromatics, and use of biodiesel in a conventional diesel engine results in substantial reduction of unburned hydrocarbons, carbon monoxide and particulate matter.  A U.S. Department of Energy study showed that the production and use of biodiesel, compared to petroleum diesel, resulted in a 78.5% reduction in carbon dioxide emissions.  Moreover, biodiesel has a positive energy balance.  For every unit of energy needed to produce a gallon of biodiesel, at least 4.5 units of energy are gained.

Energy Security Benefits 

With agricultural commodity prices approaching record lows, and petroleum prices approaching record highs, it is clear that more can be done to utilize domestic surpluses of vegetable oils while enhancing our energy security.  Because biodiesel can be manufactured using existing industrial production capacity, and used with conventional equipment, it provides substantial opportunity for immediately addressing our energy security issues.

If the true cost of using foreign oil were imposed on the price of imported fuel, renewable fuels, such as biodiesel, probably would be the most viable option.  For instance, in 1996, it was estimated that the military costs of securing foreign oil was $57 billion annually.  Foreign tax credits accounted for another estimated $4 billion annually and environmental costs were estimated at $45 per barrel.  For every billion dollars spent on foreign oil, America lost 10,000 – 25,000 jobs.

Economic Benefits  

The biodiesel industry has contributed significantly to the domestic economy.  The 51,893 jobs that are currently supported by the US biodiesel industry reflect the beginning of the industry’s potential to create jobs and economic growth in the US economy.  Biodiesel has added $4.287 billion to the Gross Domestic Product (GDP). 

Biodiesel has the potential to support more than 78,000 jobs by 2012.  A stable, thriving biodiesel industry is necessary if the U.S. is to eventually benefit from the commercial scale production of algal-based biofuels.  The NBB estimates that for every 100 million gallons of biodiesel that is produced from algae, 16.455 jobs will be created and $1.461 billion will be added to the GDP.   Quality Benefits

Biodiesel is registered as a fuel and fuel additive with the EPA and meets clean diesel standards established by the California Air Resources Board (CARB).  B100 (100 percent biodiesel) has been designated as an alternative fuel by the U.S. Department of Energy and the U.S. Department of Transportation.  Moreover, in December 2001, the American Society of Testing and Materials (ASTM) approved a specification (D675) for biodiesel fuel.  This development was crucial in standardizing fuel quality for biodiesel in the U.S. market.  As of 2008, there is a specification for B6-B20, and up to B5 is included in the diesel fuel specification (D 975).  

The biodiesel industry also utilizes a voluntary quality management certification program for biodiesel producers, marketers, and laboratories called the BQ-9000 Program.  The BQ-9000 Program combines internationally accepted quality management principles with the ASTM biodiesel fuel specification to help ensure that customers and end users get the highest quality fuel possible.  The National Biodiesel Accreditation Commissions issues ‘BQ-9000 Marketer,’‘BQ-9000 Producer’ and 'BQ-9000 lab' certifications for biodiesel marketers and/or producers and biodiesel testing laboratories that have met all requirements of quality management system certification program.  BQ-9000 companies are subject to annual third-party audits to verify their continued compliance with the program requirements.  The BQ-9000 program provides added assurance to customers, as well as engine manufacturers, that the biodiesel marketed by these companies meets the ASTM standards for biodiesel and that the fuel supplier will stand behind its products.  

EPAct Benefits

Effective November 1998, Congress approved the use of biodiesel as an Energy Policy Act (EPAct) compliance strategy.  The legislation allows EPAct-covered fleets (federal, state and public utility fleets) to meet their alternative fuel vehicle purchase requirements simply by buying 450 gallons of pure biodiesel and burning it in new or existing diesel vehicles in at least a 20% blend with diesel fuel.  The Congressional Budget Office and the U.S. Department of Agriculture have confirmed that the biodiesel option is the least-cost alternative fuel option for meeting the Federal government’s EPAct compliance requirements.  Because it works with existing diesel engines, biodiesel offers an immediate and seamless way to transition existing diesel vehicles into a cleaner burning fleet.

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Steam Systems

Generating steam is the primary function of most boiler systems. In some industries, where 40-60 percent of all energy is consumed in the generation of steam in fired or wasteheat boilers, efficient operation and regular maintenance can represent a great potential in energy savings.

Industrial Steam Trapping Handbook

For instance, in the absence of an effective maintenance program, it’s common to find 15 to 20 percent of steam traps not working properly. Another energy-waster is to allow steam leaks to persist, reducing steam production by as much as three to five percent. Insulation deterioration can cause another 5 to 10 percent steam loss during rain storms, as the insulation gets wet and loses its effectiveness. Fouled turbines and exchangers can cause as high as a 25 percent efficiency loss.

In a discussion on steam systems, many over-laps may occur when addressing maintenance and operation procedures. For example, Chapter 2, Water Treatment, discusses the addition of amines to keep the pH of the condensate high, avoiding acid attack. In this chapter, that subject is related to corrosion in steam traps, a specific problem area in steam systems.

Besides its use and subsequent availability in numerous industrial processes and also in generating electricity, steam is also employed to drive pumps and compressors as well as providing freeze protection for winter operations. Steam system operation is complex because of its generation, distribution, recovery and use at several different pressure levels.

There are five general “rules” that should be followed for maximum efficiency in steam generation. They are:

1.     Always produce steam at the highest possible temperature and pressure. This is a basic thermodynamic and economic principle.

2.     Always apply steam to process use at the lowest possible pressure and temperature levels.

3.     In fired boilers, only produce steam for valid end uses, such as process steam and reboilers.

4.     Always expand steam from a higher pressure level to a lower pressure level through the most efficient means possible.

5.     Always produce maximum steam from process wasteheat recovery systems.

Proper steam system design will greatly increase operational efficiency. Poorly designed steam traps are the ones mot likely to function improperly or fail completely. Steam Tracing systems (a system designed to monitor steam temperature on a process pipe, for example), frequently evolve in a hap-hazard manner, often to solve a short-term problem, such as a steam trap that doesn’t work. Leaks, freezing, steam system dead-ends and equipment damage can all be consequences of improper design. Heat loss can be avoided by proper insulation design and maintenance.

Because there are so many different potential problem areas to address, it is helpful segregate as many of them as possible in common groups.

General Operational Procedures

1.     Process analyzers and advanced control techniques should be employed to minimize energy consumption of plants. Many plants use feed preheaters to supply heat for operation. Significant energy savings can be associated with system optimization. Specific operating control targets should be employed with energy conservation in mind.

2.     Improperly operated vacuum systems can significantly increase steam usage. Any leaks that develop should be repaired.

3.     Every operating area should have checklists and Standard Operating Instructions (SOIs) to ensure that unneeded steam traps and tracing systems are turned off as they can be a significant source of steam usage. Tracing systems are routinely left on year-round but are only needed during the colder months.

4.     Steam consumption targets and guidelines should be established at all facilities and for all major pieces of equipment. Targets should be routinely adjusted for process feed-rate changes. Target consumption should be plotted relative to load (load curves). The goals should be to operate the plant on these load curves.

5.     Each steam generator should be rated according to its performance characteristics or efficiency. That way, during a period of in-creasing steam demand, the most efficient generators can be loaded first, keeping energy consumption to a minimum while getting the most steam out of the most efficient systems. Also, where options exist and there is flexibility, the most efficient systems should be used first.

6.     Steam systems should be surveyed routinely to identify seldom-used steam lines which could be removed from service. Adjustments to systems should be made as dictated by plant steam requirements. If not automated, these adjustments should be described in a set of clearly stated, written instructions to the operator.

6.     Steam tracing systems should be held to an absolute minimum, as their use can down-grade overall steam distribution efficiency. Alternatives to steam tracing should be investigated, such as electrical heating tapes for remote locations where the monitoring of a steam tracing system would be impractical.

7.     Steam distribution and condensate systems should be designed so that effective corrosion treatment systems can be employed. See Chapter 2, Water Treatment, for information on these treatment systems.

8.     Steam systems should also be designed with adequate metering to be able to keep track of where the steam is going and to routinely get facility-wide and individual process-unit steam balances.

Steam Traps

1.     Every operating area should have a program to routinely check steam traps for proper operation. Testing frequency depends on local experiences but should at least occur yearly.

2.     All traps should be numbered and locations mapped for easier testing and record-keeping. Trap supply and return lines should be noted to simplify isolation and repair.

3.     Maintenance and operational personnel should be adequately trained in trap testing techniques. Where ultrasonic testing is needed, specially trained personnel should be used.

4.     High maintenance priority should be given to the repair or maintenance of failed traps. Attention to such a timely maintenance procedure can reduce failures to three to five percent or less. A failed open trap can mean steam losses of 50-100 lb/hr.

5.     All traps in closed systems should have atmospheric vents so that trap operation can be visually checked. If trap headers are not equipped with these, they should be modified.

6.     Proper trap design should be selected for each specific application. Inverted bucket traps may be preferred over thermostatic and thermodynamic-type traps for certain applications.

7.     It is important to be able to observe the discharge from traps through the header. Although several different techniques can be used, the most foolproof method for testing traps is observation. Ultrasonic, acoustical and pyrometric test methods often suggest erroneous conclusions.

8.     Traps should be properly sized for the expected condensate load. Improper sizing can cause steam losses, freezing and mechanical failures.

9.     Condensate collection systems should be properly designed to minimize frozen and/or premature trap failures. Condensate piping should be sized to accommodate 10 percent of the traps failing to open.

Insulation

1.     Systems should be regularly surveyed to re-place or repair missing and deteriorated insulation. This is especially important after insulation has been removed to repair steam leaks.

2.     An overall survey of steam lines should be conducted every five years (or one fifth of the facility per year) to identify areas where insulation or weatherproofing has deteriorated. Typical culprits include prolonged exposure to moisture, chemicals or hydrocarbons. Instruments to measure the effectiveness of insulation include thermographic (heat image) devices. This instrument gives an indication of surface temperatures by displaying various colors. It is ideal for large areas. Others include portable infrared pyrometers, or heat guns, that measure surface heat by infrared wave emitted from the surface and contact-type pyrometers and surface crayons, which must be in contact with the surface to measure heat.

3.     Following any maintenance work, areas where work has been performed should be inspected to see where insulation should be repaired or replaced. Removable insulation blankets should have been reinstalled on all equip- ment. The last step in any maintenance work should be the repair, replacement or reinstallation of insulation. System components often overlooked and left uninsulated include valves, turbines, pumps and flanges.

4.     Optimal insulation thickness should be applied to any new piping systems.

5.     During steam line surveys, insulation should be visually inspected for the following defects:

·         Physical damage

·         Cracks in vapor barriers

·         Broken bands or wires

·         Broken or damaged

·         weather-tight jointseals

·         Damaged covers and

·         weatherproofing

Leaks

1.     All steam leaks should be repaired as quickly as possible. Leaks are one of the most visible forms of energy waste. The table in Figure 27 shows steam loss at pounds per hour, for a given sized hole, at a given pressure. Steam leaks can also suggest management indifference to efficient operation and pose significant safety hazards. Steam leaks don’t get smaller, neither does the cost of fixing them.

2.     Standard procedures should dictate that proper gaskets and packing are used in steam system flanges and valves.

3.     An on-stream, leak-repair specialist should be employed to repair leaks when the steam system cannot be taken down.

4.     All steam systems should be designed for minimum leakage. For example, flanges and threaded piping should be minimized.

Pressure

1.     There are large incentives to use steam at its lowest possible pressure for heating, primarily to reduce energy consumption. Process or equipment changes will often allow the use of lower steam pressure. These considerations are part of the plant initial design phase and any changes recommended should undergo an economic analysis to justify process or equipment changes.

2.     The utilization of steam at all pressure levels should be maximized. High pressure steam should not be reduced in pressure through control valves and low pressure steam should not be vented. Typically, there are large in centives to eliminate steam venting and pressure letdown. A significant reduction in fuel cost is perhaps the largest incentive. Instrumentation should be designed to continuously monitor steam pressure letdown and venting. In short, all steam systems should be balanced.

3.     Reboilers and steam preheaters should use only the lowest steam pressure possible. This can often be done by using extended tube surfaces, nucleate boiling tubes and lower tower pressures.

Tabel : Estimate of steam losses

Special Notes on Turbines

1.     Steam turbines should always be operated at the lowest back pressure possible. In topping turbines, high back pressure can be caused by inadequate piping or high steam consumption from declining turbine efficiency. A high pressure drop between the turbine exhaust and the steam header could mean the piping is restrictive. In condensing turbines, high back pressure can be caused by vacuum system problems.

2.     Condensing turbines are not very efficient as they tend to lose energy and utilize only 15 to 20 percent of the available steam thermal energy. At some point, consideration should be given to replacing these turbines with top-ping turbines, electric motors or direct-drive gas turbines.

3.     Low turbine efficiency is often the result of blade fouling. Fouling is usually a result of water that has not been treated properly. See Chapter 2, Water Treatment, for further recommendations. Water-washing turbines on-stream will often restore their efficiency. Improperly treated feedwater can also cause permanent long-term damage to boiler waterwall surfaces and superheater tubes.

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