heavy oil refining

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HEAVY OIL REFINING—1: Understanding fines

in coking more important now01/07/2013

This new coker unit at Phillips 66's Wood River refinery, Roxana, Ill.,started up in November 2011 as part of a $3.8 billion coker andrefinery expansion. The project increased Wood River's clean productyield by 5%, says the company, and increased gross heavy crude oil processing capacity by 90,000-110,000 b/d. The refinery is owned byWRB Refining, a 50/50 joint venture between Phillips 66 andCenovus Energy; Phillips 66 operates the refinery. Photo from Phillips66.

Scott Sayles Sim RomeroKBC Advanced Technologies Inc.Houston

Growth in the need to upgrade heavy crude oils, such as Athabasca bitumen and others, into synthetic crudeoils as well as the need to process heavier conventional crudes is increasing the use of coking. Fines, or solids, in delayed-coker feedstocks reduce the ability of the coker to utilize capacity fully.

This first of two articles on the presence and effects of fines in delayed-coker feedstocks discusses the naturand sources of fines that enter a coking operation. The second, concluding article (OGJ, Feb. 4, 2013) willdiscuss the impact of fines and the mitigation steps that can improve reliability and profitability of the

operation.

Fines enter delayed-coker feed from several different sources. Both inorganic and organic fines degradedelayed-coker reliability and overall refinery economics. In some cases, sudden changes in the refinery or amajor upset in the refinery's desalter can bring down the delayed coker within hours.

In most cases, problems with solids fed to the coker are not as dramatic but still major.



Fines: types, sources

Fines can be classified as organic and inorganic, but there is considerable interaction between thesecategories.

• Organic solids are coke particles or coke fines and asphaltenes. Organic solids are at times a true solid

(coke fines, corrosion products) and are also precipitated asphaltenes both of which form a third solid phase

• Inorganic fines can be from oil sands bitumen, fluid catalytic cracking catalyst, ebullated-bed heavy oilhydrocracker catalyst, or corrosion from upstream equipment.

Inorganic or organic salts that can form from amine and chloride components can also be thought of as solidand can degrade operations of the delayed coker. This discussion does not address salt formation in thefractionator and downstream, as the breadth of that topic warrants separate treatment.

Organic fines

Organic fines are primarily hydrocarbons but typically have some inorganic constituents, such as metals,sulfur, oxygen, and nitrogen. Coke fines are the single largest type in a delayed coker. They can be a problem both in primary process operations and in ancillary operations such as coke cutting and coke handling.

When the coke drums are being filled, coke fines can be entrained in the drum overhead into the fractionatoas a result of high vapor velocities and high foam fronts. The fines are relatively consistent in shape and sizeThe very small fines, smaller than 50µ, are solid rectangular shapes with a specific gravity of about 1.7. Alarge quantity of larger particles can also exit with the vapor due to high velocities, full drums, and largefoam fronts.

These larger particles can be as large as 0.25 in. or 50 mm. At some locations, these very large fines canactually be heard escaping the top of the drum. These large particles are less dense and can be spherical or resemble small shot-coke particles. These larger particles can be recovered in the fractionation bottoms'circulation system.

Sometimes sediment forms as a result of phase incompatibility among cracked products. The sediment can basphaltene precipitation, wax formation, or other molecules that form solids as composition changes.Sedimentation can be reversible (waxes) or nonreversible (asphaltene precipitation). Much has been writtenabout sedimentation, but it remains poorly understood. Sedimentation can manifest itself as a solid or as asticky pitch or gum.

Historically, the delayed-coker feed asphaltene content, in conjunction with the Conradson Carbon content, used to predict the propensity for sedimentation. Canadian feeds have relatively high asphaltenes contentcompared with typical crudes. Other feed types such as a deasphalted feed might have much lower asphaltenes content, while ebullated-bed vacuum residua would have more.

Asphaltenes are particles in the submicron range and can agglomerate to form micron-sized particles. Theseare often neglected in the discussion of fines and their impact on operations.

The vapors leaving the coke drum also entrain very small pitch particles in the form of an aerosol spray or mist. Again, the amount of unconverted heavy oils or pitch carried out of the drum is a strong function of the



drum's vapor velocities, the level in the drum, and the amount of foam, or unconverted coke, at the top of thdrum.

Fig. 1 illustrates a full drum with solids and pitch carryover.

The height of the foam front in the online coke drum can be determined by taking several factors intoaccount. The foaming calculations roughly estimate the foaming potential of different crude blends and howthese blends interact under different coke drum operations, such as temperature, recycle, pressure, cycle timand drum utilization or coke level in the drum.



Fig. 2 shows the general relationship of how two dissimilar crudes will interact as the coke drum temperaturincreases. The detailed impacts on foam height will depend on the qualities and ratios of the specific crudesin combination with coker operating conditions.

Inorganic fines

Inorganic fines are FCC catalyst, ebullated-bed catalyst fines, corrosion deposits, bitumen sand, and other <100µ solids entering the coker via the feed.

FCC slurry contains catalyst fines typically in the 20-60µ range. Catalyst fines have a very high surface areaand relatively low density and are not removed by the bottoms' filtration circuit. The concentration can varywidely; most are <0.1 wt %.

Many techniques measure FCC catalyst slurry fines. The particle size and distribution are not routinelytested, but this can be done by the licensor upon request. The quantity of fines should be measured daily andis a monitoring point for the coker operation.

Ebullated-bed fines come from the vacuum tower bottoms of an ebullated-bed heavy oil hydrocracker and ain the 100µ range. This catalyst has a higher density and lower surface area than FCC catalyst. Due to their larger size and higher density, some of these fines would be removed by the bottoms' filtration circuit.

Concentration is low, typically <0.02 wt %.

Corrosion products are generally iron sulfides or iron oxides as well as other typical scale materials. Physica properties and size are highly variable and unpredictable. Measurement is equally difficult, as often thecorrosion products will enter the unit in a slug triggered by an upstream event (for example, returning a tankto service after cleaning). The bottoms filtration will remove some corrosion products, but not all. Somecorrosion products such as iron oxide can foul the heater tube rapidly.



Upgrading oil sands bitumen increases the product quality from the extracted bitumen to synthetic crude oilFig. 3 shows that the value of the product increases in relationship to the quality, but this requires higher production costs and operational complexity.

Bitumen is upgraded with a primary bottom-of-the-barrel process such as an ebullated-bed hydrocracker or delayed coker. Bitumen is separated from the sand and most of the sand is removed and returned to theexcavation site. Some of the sand remains, however, and is transported into the primary upgrader.

Bitumen sand is a high surface-area particle surrounded by bitumen. The particles are 1-10µ and notfilterable. The silt-like quality of these particles allows them to migrate throughout the piping systems as asuspension with the oil.

Analyzing the oil for titanium can detect these particles. The titanium concentration is low, typically 1-20 ppm (wt), but is a good marker for inorganics originating from bitumen silt. The change in titaniumconcentration is one of the significant differences and is a good marker for silt originating from Athabasca bitumen. The titanium content is proportional to the fines content of the bitumen (Fig. 4).

Other sources of inorganic solids are slops originating from the coke drum's overhead line quench and fromgray water used to cool or quench coke in the drum. The solids in the water are typically coke fines, but thewater can also contain a variety of inorganic solids as well.



Solids, both organic and inorganic, introduced in the cooling and quench of the coker rarely enter primary processing operations and are confined to the coke cutting and quench water system and the coke-handlingsystem. Slops injected into the coke drum overhead line as a line quench, however, will enter the processdirectly and will have immediate consequences.

The authors

Scott Sayles ([email protected]) is a principal consultant for KBC Advanced Technologie

Inc., Houston, with more than 30 years of refinery and petrochemical experience, rangingfrom refinery plant manager to research engineer.His technical areas of expertise includeoperation and design, ebullated-bed residua hydrocracking, hydrotreating, FCCU, and practical understanding of most processes. Sayles is a member of the American Fuel andPetrochemical Manufacturers. He holds a BSChE from Michigan Technological UniversityHoughton, Mich., and an MSChE from Lamar University, Beaumont, Tex.

Sim Romero ([email protected]) is a principal consultant for KBC AdvancedTechnologies Inc. with more than 30 years as a chemical engineer. He spent 11 years withConocoPhillips in delayed coking, then 7 years with BP Oil in heavy oils and delayed

coking. He moved to ARCO then back to the Conoco/Bechtel Alliance in delayed coking,with a short stay with ExxonMobil, and then spent 7 years with Valero as director of heavyoils and delayed coking, before joining KBC. Romero is a member of the American Fueland Petrochemical Manufacturers and sits on the technical steering committee for Coking.com. He holds a BS in chemical engineering from the University of New Mexico, Albuquerque.

mailto:([email protected]






HEAVY OIL REFINING—2 (Conclusion):

Analysis, appropriate steps can mitigate effects of

coking fines

02/04/2013

Scott Sayles Sim RomeroKBC Advanced Technologies Inc.Houston

This second, concluding article discusses the impact of fines in delayed-coker feedstocks and the steps thatcan improve reliability and profitability of the coking operation. The first article (OGJ, Jan. 7, 2013, p. 82)discussed the nature and sources of fines that enter the coking operation.

Growth in the need to upgrade heavy crude oils, such as Athabasca bitumen and others, into synthetic crudeoils and in the need to process heavier conventional crudes is increasing the use of coking. Fines, or solids, delayed-coker feedstocks reduce the ability of the coker to utilize capacity fully.

Impact

There are always organic fines in the delayed-coker process; it's the nature of the process. Inorganic solids,however, are not as typical, and it's the interaction of the organic and inorganic solids that causes mostfouling.

A summary of fines' effect on the delayed coker follows:

• Fines accumulate in low-velocity zones provided the fluid temperature is sufficiently high to reduceviscosity enough for solids settling. Solids, or fines-containing streams, within the delayed coker are

not filterable. The fractionator bottoms' system strains for large coke and does not remove fines.

• Pumps are prone to erosion due to fines. Protection of pump seals by flush designs is critical to longruns.

• The fractionator's run is affected by the accumulation of fines and sludge in the lower section of thetower, specifically on the heavy gas oil draw pan. During drum switches and low heavy coker gas oilflow, the risk of low tray velocities or dry trays increases the risk of solids accumulation. Design of th pumparound and good operational procedures are needed to prevent this from occurring.

• The fractionator bottoms strainer is designed to collect fines. There are micron-size fines, however,

which the bottoms strainer will not remove and which will migrate into the heater charge pump andtubes.

• The lower tower section–the flash or wash zone–will experience increased coke buildup or fouling.



• With solids in the feed, coke formation in furnace tubes tends to be harder than non-solids containinfeeds. Although this effect has been associated with fines in the feedstock, it appears difficult toseparate this effect from higher average asphaltene levels. In general, feeds such as Athabasca bitumerequire pigging to remove the coke because steam air decoking and online spalling are insufficient.

• Drum operation tends to have higher more stable foam fronts during the coking cycle andimmediately after the switch to steam. Antifoam use is effective in controlling the foam front.

• The coke drum's overhead line will have increased coke build-up due to the high solids leaving thecoke drum.

Fractionator bottoms

The tower bottom section serves as a feed drum for the heater charge pumps. The fresh coker feed is the hotvacuum-tower bottoms or preheated feed from tankage. Feed enters above the bottom liquid level and mixewith the wash oil liquid that flows countercurrent to drum vapors (internal recycle). The mixed stream enterthe heater charge pumps to the coker heater.

The coke drum vapors carry coke fines into the bottom of the fractionator along with other fines entering the

system in the bottoms feed stream. This results in the need to clean the bottom circulation system's filtersevery 2-3 weeks, depending on the coke drum's vapor velocities (Fig. 1).

Fractionator filters are typically designed to remove 3⁄16-in. particles. Because this is too large for finesremoval, these smaller particles generally pass into the downstream equipment.



Feed preheat exchangers

The feed preheat exchangers increase the temperature of the vacuum residua or other feeds and, as a result,reduce the viscosity of the stream. In general, lower viscosity allows solids to settle more rapidly, creatingaccumulation of solids in the low-velocity zones in the heads and outlet piping.

Heater charge pumps

The heater charge pumps feed the fractionator bottoms product, a combination of fresh feed and recycle, tothe coker heaters along with entrained fines.

The presence of fine particles requires installation of an adequate pump suction strainer to catch bigger particles and avoid damage to the impeller. Alternatively, the pump is designed with an impeller that crushecoke particles to a size the pump impeller can tolerate. The suction strainer removes some of the coke finesfrom entering downstream.

Plugging of the strainers and the necessary switch of pumps for strainer cleaning cause operational upsets.The coke-crushing impeller option allows continuous operation but increases fines to the heater anddownstream systems where they can cause erosion, coke seeds for tube coking, and foaming in the drums.

Heater

The heater is prone to coking or fouling that is directly related to the heat flux, fluid velocities, andasphaltene content. An addition of organic or inorganic fines increases the fouling or accumulation of solidswithin the heater tubes. Tube coking is described elsewhere;1 2 only the contribution of solids will bediscussed here.

Settling typically occurs when the tube's liquid/vapor velocity falls to less than the "salting" velocity. Insolids transportation, horizontal transport velocity required to move solids is well known. A velocity below

which the solids settle to the bottom of the pipe is the "salting" velocity. Transport occurs at velocities greatthan this.

In the delayed coker's heater, these velocities are greater than salting velocities. In addition, the unvaporized particles of liquid or continuous liquid phase would tend to retain the solids because of the adhesion(stickiness) of the fluid.

Coke formation in the tubes for heaters with high solids contents tends to be harder than non-solidscontaining feeds. In general, feeds such as Athabasca bitumen require pigging to remove the coke becausesteam air decoking is insufficient. With high solids or silt in the feed, spalling during the run is alsoineffective, depending on the concentration of inorganic solids.

An additional contributor is sodium. This can be an inorganic (salt, caustic) or an organic particle (sodiumnaphthenate), which can accelerate fouling in the delayed coker's heater.

Finally, iron oxide or any oxygen-free radical contaminant will accelerate heater-tube fouling. Similar to the process of using oxygen to polymerize asphalt (air blowing) and increase asphalt viscosity, iron oxide willreact with asphaltenes in the delayed coker's feed to cause rapid fouling in the heater.



Coke drum

The vaporized liquids and entrained solids enter the drum from the bottom. The coking reactions aredescribed elsewhere;3 this discussion is about the impact of fines on the physical separation of the oil andgas.

The theory most relevant to this discussion is that the presence of fines inhibits the ability of the liquid todrain between the bubble micelles. This slows the entire bubble structure's ability to collapse. Other

constituents, such as sodium naphthenates (a soap), will enhance the foam structure by reducing the surfacetension of the oil phase.

The major contributor to foam production is the velocity of the vapor phase through the drum. This has beencovered elsewhere.4 The assumption here is that the drum is operating in a reasonable velocity range.

Solids entering the system as micron particles will stabilize the foam. Asphaltene precipitation andagglomeration will provide additional fines to the system. Foaming can also occur during the steaming cyclereferred to as a "re-foam."

Re-foaming is a result of steam changing the partial pressure of the liquid vapor in the drum. The sudden

injection of steam lowers the partial pressure and rapidly lowers the effective boiling point of the remainingliquids in the drum. The rapid vaporization increases the vapor velocities in the drum and restarts thefoaming in the drum. Fines in the system aggravate this, creating more severe or intense foaming.

Antifoam is the typical mitigation answer to foam formation but does not always provide the required foam-front reduction.

Overhead vapor line

The top of the progressing coke formation has a layer of foam, which collapses and allows the vapor producto leave the drum. Some solids always leave the coke drum, a function of foam height and stability and of thvelocity of the vapors in the drum. The vapors leaving are not clean and clear but an aerosol spray or mist.Extremely small solids in the coker feed will add to this aerosol spray and contribute to the fouling of all thedownstream equipment–the overhead line and the bottom of the fractionator–any dry surface.

The foam height can be calculated with the KBC coke morphology model. The kinetic foam portion of thatmodel uses the drum's operating conditions and feed quality to predict foam height. Solids will also increasefoam height during this step.

Fractionator top section

The second and larger section of the main fractionator fractionates coke drum vapors, which containentrained solids. These vapors from the coke drums are oil quenched (which may contain fines), entering thfractionator between the bottom and the wash section. In the wash section, the coke drum's vapors contact thhot wash-oil stream, usually filtered heavy coker gas oil (HKGO). Wash oil quenches the drum vapors andwashes out most of the entrained coke fines. A design with an empty flash zone and elimination of sheddecks greatly reduces this problem.

The liquid phase leaving the wash zone is the internal recycle, mixing with the fresh feed, and contains solidfrom all sources. Typical conditions are >750° F. and 20-25 psig.



The section above the wash zone is the heavy gas-oil section. Vapors leaving the wash zone contact theheavy gas oil pumparound. The product drawn from the bottom of this section is HKGO. The middle sectionis the light gas oil section (LKGO) where the vapor phase contacts the LKGO pumparound. The productdrawn is LKGO. In the top, or naphtha, section of the fractionator, the remaining vapor contact is with thetop reflux.

HKGO is typically the heaviest side product drawn from the fractionator. It is steam stripped, filtered,hydrotreated, and used as feed component for fluid catalytic cracking (FCC) units or as a blendingcomponent for fuel oil. Depending on the hydrotreater configuration for FCC feed, in some cases LKGO andHKGO are combined at the coker battery limits.

HKGO filtration

HKGO filter systems remove coke fines from the heavy gasoil stream for feed to a hydrotreater or other downstream unit. The most common filter systems use mesh or edge disk filters (wedge wire) and backwashto remove collected solids. These filter systems typically have reliability and operational problems, the moscommon being an excessively high frequency of backwash cycles to clean the plugged filter elements.

The filter elements often lack sufficient surface area and are operating at lower temperature, which causes

asphaltenes to precipitate out on the filter elements, making backwashing very difficult. Sand filters can beused to clean the HKGO (static filter system, no backwash necessary) but create considerable hazardouswaste and are not recommended.

Removal efficiency is a function of the solids' particle size. Larger-particle removal is nearly 100%, whilesmaller particles are less.

HKGO pumps

Generally, HKGO pumps are for product and pumparound streams. The cyclic nature of delayed coking provides a wide range of flow for these pumps. Before the drum switch, part of the drum vapors flowsthrough the empty coke drum to preheat the offline coke drum. This part of the drum vapor bypasses themain fractionator, reducing the tower vapor-liquid traffic, reducing the amount of HKGO draw.

Solids in the liquid are prone to deposit during this part of the cycle if tray velocity is low and trays becomedry. This problem is more pronounced in a two-drum system. Conversely, a four or more drum system,feeding a common fractionator, may never see a large reduction in liquid tray velocities.

Coke fines can also enter the hydraulic system via breathing vents and gaps in the reservoirs. Fines can caussignificant damage to the cylinders, pumps and other parts of the system.

InstrumentationSpecification for the instruments includes the ability to handle solids-containing streams. In addition to thenormal precautions taken for coking services, additional protections are needed to keep fines away frominstrumentation. Impulse line taps on the top of the line with purges can be effective. Flow measurement thauses wedge meters is acceptable. Control-valve specifications should be set to prevent erosion whilemaintaining good control.

Piping



Specifications for piping also include the ability to handle solids-containing streams. Lines should be self-draining without dead legs in the design. Minimum velocity is a consideration to prevent settling within the piping.

Reaction kinetics

Coking kinetics are changed by the presence of fines in the drum. As expected, the added surface areaincreases the coke and gas yields. This leads to the commercial observation of stable foam formation due to

fines. The postulation is that, as the coking reactions occur, more gas is formed locally, creating the foamwith coke stabilizing the formation.

The use of a first principle model to predict the coke drum performance can greatly improve unit reliability.KBC's Petro-SIM suite uses DC-SIM as the primary delayed-coker model. The model is imbedded in thePetro-SIM environment to manage the molecules efficiently.

Coke fines in cutting water

Coke cutting creates fines. Separation of the fines from the water is critical to success in delayed coking. Atypical coke fines' separation process and coke cutting system appears in Fig. 2.

Coke fines' removal in the maze and water storage tank is critical to managing fines within the unit.



Mitigation steps

The removal of fines from the coker feedstock before charging the heater provides the most benefit inmitigating the impact of fines on the operation. If unavoidable, then additional design and operationalchanges can be made.

Some design changes to consider are:

• A fractionator bottoms design with a slotted standpipe and strainer for the bottoms is a typical designthat is critical for successful operations. Other modifications to consider are removal of the shed deckand streamlining the fractionation section. Wash sprays and HKGO pumparound strainer designsintegrated for optimal performance will also provide longer runs.

• Pump designs can include coke-crushing impellers and suction strainers for removing larger coke particles. This step does not reduce the quantity of fines but does mitigate the plugging of instrumentation and control valves.

• Heaters designed with dual fired or double-fired heaters and minimizing heat flux reduces coking anthe fines trapped within the coke. The reduction in fines within the coke increases run length.

• Increasing convection-section fluid velocities to increase tube-wall shear stresses and avoid solidssettling and fouling.

Manuscripts welcome

Oil & Gas Journal welcomes for publication consideration manuscripts aboutexploration and development, drilling, production, pipelines, LNG, and processing (refining, petrochemicals, and gas processing). These may behighly technical or they may be more analytical by way of examining oil andnatural gas supply, demand, and markets. OGJ accepts exclusive articles as

well as manuscripts adapted from oral and poster presentations. An Author Guide is available at www.ogj.com, click "home" then "Submit an article."Or, contact the Chief Technology Editor ([email protected]; 713/963-6230; or, fax 713/963-6282), Oil & Gas Journal, 1455 West Loop South,Suite 400, Houston TX 77027 USA.

Operational changes

The operational changes are as follows:

• Regularly scheduled cleaning intervals along with monitoring to detect rapid pressure increases areneeded for managing strainer cleaning. Because differential pressure measurements across strainerscannot be relied upon, periodic inspection and cleaning is recommended. The frequency of strainer cleaning will depend on the coke drum's operations. A small foamover or high drum outage shouldtrigger a higher frequency of strainer cleaning.

• Monitoring the pressure drop of the coke drum overhead line and lower section of the fractionator isimportant. The throat of the overhead line will require periodic cleaning. A differential temperature

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controller, which resets the gas-oil overhead line quench, is not recommended. A simple flowcontroller with period inspection is better.

• Monitoring of heater pressure profiles and tube metal temperatures improves prediction of end of ruProjections using an operating-data regression analysis and process fouling simulation arerecommended. The Petro-SIM heater model provides a way to predict coke formation and total heaterrun length.

• During initial steam stripping, it is important to avoid rapid drum switches with slow or rampedsteam injection and to ensure the stripping steam is not wet. Ensure that steam traps are operationaland, before drum steam stripping, blow down piping prone to collect condensate.

References

1. Romero, Sim, "Delayed Coker Fired Heater Design and Operations," Rio Oil & Gas, Sept. 13-16,2010, Rio de Janeiro.

2. Romero, Sim, "Delayed Coking Process Design, Operations and Optimization," Canada CokingConference, Oct. 22-26, 2012, Fort McMurray, Alta.

3. US Patent 4,404,092 – Delayed Coking Process: Energy-use analysis and improvement for delayedcoking units; http://xa.yimg.com/kq/groups/3004572/1046193709/name/Energy-use+analysis+and+improvement+for+delayed+coking+units.pdf.

4. Elliott, John, "Fine-tune your delayed coker: obstacles and objectives,"http://www.fwc.com/publications/tech_papers/files/Fine%20tune%20your%20delayed%20coker.pdf .

http://www.fwc.com/publications/tech_papers/files/Fine%20tune%20your%20delayed%20coker.pdf

http://www.fwc.com/publications/tech_papers/files/Fine%20tune%20your%20delayed%20coker.pdf

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