HEAVY OIL REFINING—2 (Conclusion): Analysis, appropriate steps can mitigate effects of coking fines

Feb. 4, 2013
This second, concluding article discusses the impact of fines in delayed-coker feedstocks and the steps that can improve reliability and profitability of the coking operation.

Scott Sayles Sim Romero
KBC Advanced Technologies Inc.
Houston

This second, concluding article discusses the impact of fines in delayed-coker feedstocks and the steps that can 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 crude oils and in 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.

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 most fouling.

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

• Fines accumulate in low-velocity zones provided the fluid temperature is sufficiently high to reduce viscosity 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 long runs.

• The fractionator's run is affected by the accumulation of fines and sludge in the lower section of the tower, specifically on the heavy gas oil draw pan. During drum switches and low heavy coker gas oil flow, the risk of low tray velocities or dry trays increases the risk of solids accumulation. Design of the 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 and tubes.

• 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 containing feeds. Although this effect has been associated with fines in the feedstock, it appears difficult to separate this effect from higher average asphaltene levels. In general, feeds such as Athabasca bitumen require 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 and immediately 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 the coke drum.

Fractionator bottoms

The tower bottom section serves as a feed drum for the heater charge pumps. The fresh coker feed is the hot vacuum-tower bottoms or preheated feed from tankage. Feed enters above the bottom liquid level and mixes with the wash oil liquid that flows countercurrent to drum vapors (internal recycle). The mixed stream enters the 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 filters every 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 fines removal, 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, creating accumulation 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, to the 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 crushes coke particles to a size the pump impeller can tolerate. The suction strainer removes some of the coke fines from 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 and downstream 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, and asphaltene content. An addition of organic or inorganic fines increases the fouling or accumulation of solids within the heater tubes. Tube coking is described elsewhere;1 2 only the contribution of solids will be discussed here.

Settling typically occurs when the tube's liquid/vapor velocity falls to less than the "salting" velocity. In solids 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 greater than 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-solids containing feeds. In general, feeds such as Athabasca bitumen require pigging to remove the coke because steam air decoking is insufficient. With high solids or silt in the feed, spalling during the run is also ineffective, depending on the concentration of inorganic solids.

An additional contributor is sodium. This can be an inorganic (salt, caustic) or an organic particle (sodium naphthenate), 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 will react 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 are described elsewhere;3 this discussion is about the impact of fines on the physical separation of the oil and gas.

The theory most relevant to this discussion is that the presence of fines inhibits the ability of the liquid to drain 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 surface tension of the oil phase.

The major contributor to foam production is the velocity of the vapor phase through the drum. This has been covered 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 and agglomeration will provide additional fines to the system. Foaming can also occur during the steaming cycle, referred 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 remaining liquids in the drum. The rapid vaporization increases the vapor velocities in the drum and restarts the foaming 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 product to leave the drum. Some solids always leave the coke drum, a function of foam height and stability and of the velocity 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 the downstream 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 that model uses the drum's operating conditions and feed quality to predict foam height. Solids will also increase foam height during this step.

Fractionator top section

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

The liquid phase leaving the wash zone is the internal recycle, mixing with the fresh feed, and contains solids from 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 the heavy gas oil pumparound. The product drawn from the bottom of this section is HKGO. The middle section is the light gas oil section (LKGO) where the vapor phase contacts the LKGO pumparound. The product drawn is LKGO. In the top, or naphtha, section of the fractionator, the remaining vapor contact is with the top 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 blending component for fuel oil. Depending on the hydrotreater configuration for FCC feed, in some cases LKGO and HKGO 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 backwash to remove collected solids. These filter systems typically have reliability and operational problems, the most common 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 be used to clean the HKGO (static filter system, no backwash necessary) but create considerable hazardous waste and are not recommended.

Removal efficiency is a function of the solids' particle size. Larger-particle removal is nearly 100%, while smaller 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 flows through the empty coke drum to preheat the offline coke drum. This part of the drum vapor bypasses the main 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 become dry. 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 cause significant damage to the cylinders, pumps and other parts of the system.

Instrumentation

Specification for the instruments includes the ability to handle solids-containing streams. In addition to the normal precautions taken for coking services, additional protections are needed to keep fines away from instrumentation. Impulse line taps on the top of the line with purges can be effective. Flow measurement that uses wedge meters is acceptable. Control-valve specifications should be set to prevent erosion while maintaining 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 area increases 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 foam with 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 the Petro-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. A typical 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 in mitigating the impact of fines on the operation. If unavoidable, then additional design and operational changes 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 design that is critical for successful operations. Other modifications to consider are removal of the shed decks and streamlining the fractionation section. Wash sprays and HKGO pumparound strainer designs integrated 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 and the 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 solids settling and fouling.

Manuscripts welcome

Oil & Gas Journal welcomes for publication consideration manuscripts about exploration and development, drilling, production, pipelines, LNG, and processing (refining, petrochemicals, and gas processing). These may be highly technical or they may be more analytical by way of examining oil and natural 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 are needed for managing strainer cleaning. Because differential pressure measurements across strainers cannot 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 should trigger a higher frequency of strainer cleaning.

• Monitoring the pressure drop of the coke drum overhead line and lower section of the fractionator is important. The throat of the overhead line will require periodic cleaning. A differential temperature controller, which resets the gas-oil overhead line quench, is not recommended. A simple flow controller with period inspection is better.

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

• During initial steam stripping, it is important to avoid rapid drum switches with slow or ramped steam injection and to ensure the stripping steam is not wet. Ensure that steam traps are operational and, 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 Coking Conference, Oct. 22-26, 2012, Fort McMurray, Alta.

3. US Patent 4,404,092 – Delayed Coking Process: Energy-use analysis and improvement for delayed coking 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.