Patent Application
20090266742
This invention relates to methods for reducing furnace fouling in delayed coking processes, and more particularly in delayed coking processes in which the coker feedstock has a high propensity for furnace fouling.
Delayed coking is a non-catalytic thermal cracking process for treating various low value residual (“resid”) streams from petroleum refinery processes. The treatment enhances the value of such streams by converting them to lower boiling cracked products. In a conventional delayed coking process, as described for example in U.S. Pat. No. 4,455,219, feedstock is introduced to a fractionator to produce an overhead stream, a bottoms stream and at least one intermediate stream. The fractionator bottoms stream including recycle material is heated to coking temperature in a coker furnace. The heated feed is then transferred to a coke drum maintained at coking conditions of temperature and pressure where the feed decomposes to form coke and volatile components. The volatile components are recovered and returned to the fractionator. When the coke drum is full of solid coke, the feed is switched to another drum, and the full drum is cooled and emptied by conventional methods. Alternatively, feedstock may be supplied to the coker furnace without first passing through a fractionator, as described for example in U.S. Pat. No. 4,518,487.
The delayed coking process employs a furnace that operates at temperatures as high as about 1000° F., roughly 50 to 100° F. higher than the operating temperature of the coke drum. The high furnace temperatures can promote the rapid formation of insoluble coke deposits on the furnace tubes and transfer lines. When coke deposits reach excessive levels, the operation must be shut down and the furnace de-coked. Frequent interruptions for cleaning can lead to high operating costs due to increased amounts of time the operation is off-line, in addition to the costs of the de-coking operations.
Although the process is referred to as “coking”, coke is often the least valuable product of the operation. Thus, it is often desirable to minimize the amount of coke produced and maximize the production of other cracked products such as coker gasoline, distillates, and various gas oils. One approach to the problem of furnace fouling is described in U.S. Pat. No. 4,455,219, wherein an internal recycle stream of volatile components produced during the coking operation (for example, flash zone gas oil, heavy coker gas oil, light coker gas oil, and coker naphtha) is substituted for part of the conventional coker heavy recycle stream. This approach reduces furnace fouling when using conventional coker feedstocks, but is not adequate to control furnace fouling when using coker feedstocks having a high propensity for furnace fouling. Although small amounts of feedstocks having a high propensity for furnace fouling can be blended in with conventional coker feedstocks, using them as the primary source of feed or blending them in large amounts with conventional feeds to a coker has not heretofore been feasible because of furnace fouling problems.
Thus, fouling of coker furnaces remains a costly problem.
This invention provides a method for reducing furnace fouling in a delayed coking process by increasing the aromaticity of the coker feedstock upstream of the coker furnace.
For simplicity, the term “aromatic gas oil” is used herein to refer to “an unhydrotreated aromatic gas oil, an unhydrotreated decant oil fraction, and combinations thereof.” Similarly, the term “hydrotreated aromatic gas oil” is used herein to refer to “a hydrotreated aromatic gas oil, a hydrotreated decant oil fraction and combinations thereof.”
In one embodiment, the invention provides a method for reducing furnace fouling in a delayed coking process in which the coker feed is supplied to the bottom of the coker fractionator to produce an overhead stream, a bottoms stream and at least one intermediate stream and the aromaticity of the bottoms stream is increased by combining with the bottoms stream at least one added stream upstream of the coker furnace to produce a modified stream.
In another embodiment, the invention provides a method for reducing furnace fouling in a delayed coking process in which the coker feed is supplied to the coker furnace without first passing the feed through the fractionator and the aromaticity of the feed is increased by combining with the feed at least one added stream upstream of the coker furnace to produce a modified stream.
The present invention provides methods for reducing furnace fouling in a delayed coking process, and thus, can provide longer run times between furnace cleanings.
The present invention provides a method for reducing furnace fouling in a delayed coking process wherein at least one coker feed is supplied to a delayed coking unit comprised of a coker furnace, at least two coke drums and a coker fractionator comprising the steps of
X=(A %)−[(0.02)·(hydrogen uptake in the hydrotreater)]
In another embodiment, the present invention provides a method for reducing furnace fouling in a delayed coking process wherein at least one coker feed is supplied to a delayed coking unit comprised of a coker furnace, at least two coke drums and a coker fractionator comprising the steps of
X=(A %)−[(0.02)·(hydrogen uptake in the hydrotreater)]
In yet another embodiment, the present invention provides a method for reducing furnace fouling in a delayed coking process wherein at least one coker feed is supplied to a delayed coking unit comprised of a coker furnace, at least two coke drums and a coker fractionator comprising the steps of
X=(A %)−[(0.02)·(hydrogen uptake in the hydrotreater)]
The following general description of the delayed coking process is described with reference to
Feedstock
Common feedstocks for the production of anode or fuel grade cokes are atmospheric and vacuum resid streams obtained during the distillation of crude oil. For the production of low-sulfur recarburizer coke, pyrolysis tars are often used as the primary feedstock. Often, the feedstock will be a combination of several components, including, but not limited to, crude oil resids, pyrolysis tars, thermal tars, or slurry oils. In addition to the foregoing conventional coker feedstocks, there is an interest in coking feedstocks such as solvent deasphalted pitch, visbreaker bottoms and deep resids having a very high boiling range, such as from 1000° F. and up which have a high propensity to foul the coker furnace, even when relatively high recycle rates are used to dilute the feed to the coker furnace.
System
Referring now to
Still referring to
Another embodiment of the delayed coking process is described with reference to
Coking
Referring again to
During the retention time in coke drum 150, heated stream 140 decomposes into coke and lighter hydrocarbons, which are vaporized and removed from the drum as overhead vapors 170. Overhead vapors 170 from coke drum 150 are returned to coker fractionator 20 for recovery and possible recycle to the coke drum via line 120. When coke drum 150 is full of solid coke, the heated stream 140 is switched to another coke drum 150′, and the full drum is cooled and emptied by conventional methods.
Coker Feed Modification
The aromaticity of the gas oil in modified stream 120 has been correlated to the coking propensity of the modified stream 120, as determined by the onset-of-coke-formation time (“OCFT”). As can be seen in
Reductions in the coking propensities of feedstocks have also been linked with the selection of particular fractions of the added stream used to form modified stream 120. In particular, aromatic gas oils that boil between about 650 and about 1,000° F. have shown an improved ability to reduce the coking propensity of coker furnace feed streams when added to those streams. Still more particularly, the added streams preferably have a boiling point in a range of about 750 to about 950° F., and more preferably between about 750 and about 850° F.
Thus, according to the present invention, fouling is decreased by increasing the aromaticity of the coker feedstock upstream of the coker furnace. The desired increase in aromaticity can be achieved through the addition of streams having certain desired properties to the coker feed stream. As described in detail below, the additional streams may comprise one or more of the recycle fractions from fractionator 20 and at least one of aromatic gas oil stream 100 or decant oil stream 116.
Referring to
In certain embodiments of the present invention, an aromatic gas oil stream 100 is added to fractionator bottoms stream 70 to reduce the coking propensity of bottoms stream 70. Aromatic gas oil stream 100 may comprise an aromatic gas oil from a needle coker operation (referred to as a premium coker gas oil) or heavy cycle oil from a fluid catalytic cracking (FCC) process. In some embodiments, aromatic gas oil stream 100 may also include hydrocarbons from other refinery processes such as a thermal cracker, so long as aromatic gas oil stream 100 boils between roughly 650 and 1000° F. Aromatic gas oil stream 100 preferably has a carbon aromaticity of at least about 40% and more preferably at least about 50% and still more preferably at least about 60% as measured by 13C NMR based on the total carbon content of the aromatic gas oil.
As an alternative or in addition to aromatic gas oil stream 100, a decant oil stream 116 can be added to fractionator 20 just above the flash zone gas oil tray. Decant oil stream 116 preferably has an aromatic carbon content of at least 40% and more preferably at least 50% and still more preferably at least 60% as measured by 13C NMR based on the total carbon content of the decant oil. Likewise, decant oil stream 116 preferably boils between 650 and 950° F., but can contain material boiling above 950° F. because this higher boiling material will be removed from the fractionator via line 60. Thus, most of the hydrocarbons added via decant oil stream 116 will tend to leave fractionator 20 along with the HCGO via line 50 and thereby increase the volume and aromatic carbon content of recycle stream 90, which if used as recycle will further reduce the coking propensity of the coker feed stream before it enters furnace 130.
The amount of hydrocarbons added to bottoms stream 70 will vary depending on many process variables, including feedstock composition, feedstock quality, amount of recycle, furnace design, and furnace operating conditions. For feedstocks 10 having a higher tendency for coker furnace fouling, a greater amount of aromatic gas oil may be necessary. In many embodiments, the volume of aromatic gas oil stream 100 is such that aromatic gas oil stream 100 preferably comprises from about 1 up to about 50 wt %, and more preferably from about 5 up to about 40 wt %, and still more preferably from about 20 up to about 40 wt %, of modified stream 120, based on the total weight of modified stream 120. In some embodiments, a portion 113 (shown in phantom in
The hydrocarbons in aromatic gas oil stream 100 may be selected from (a) a gas oil having an aromatic carbon content of at least about 40% and more preferably about 50% and still more preferably about 60% based on the total carbon content of the gas oil, measured by 13C NMR; (b) a hydrotreated aromatic gas oil having an aromatic carbon content measured by 13C NMR of at least about X % according to the formula X=(A %)−[(0.02)·(hydrogen uptake in the hydrotreater)], where X is at least about 20% as measured by 13C NMR based on the total carbon content of the hydrotreated aromatic gas oil and more preferably about 30% and still more preferably about 40%, and A is the aromaticity of the unhydrotreated aromatic gas oil as measured by 13C NMR analysis and is at least about 40%, hydrogen uptake is defined as [ρ·659.5·(Δ hydrogen content (wt %) of the hydrotreater product and feed)] and ρ is defined as the density (grams/cc) of the hydrotreater feed; (c) a hydrotreated aromatic gas oil of (b) having a hydrogen uptake of between about 200 and 1000 SCFB; (d) an aromatic gas oil of (a) having an aromatic carbon content measured by 13C NMR of at least about 40% based on the total carbon content of the gas oil and a boiling point in a range of about 650 to about 1,000° F.; or (e) a hydrotreated aromatic gas oil of (b) having a boiling point in a range of about 650 to about 1,000° F. An aromatic carbon content greater than 40% measured by 13C NMR corresponds roughly to having greater than 13% of hydrogen atoms in the aromatic form as measured by H NMR analysis (
Likewise, the hydrocarbons in decant oil stream 116 may be selected from any of the sources (a)-(c) identified in the preceding paragraph. However, decant oil stream 116 can be different from stream aromatic gas oil stream 100 in that decant oil stream 116, in addition to containing material boiling between 650° F. and 1000° F., also can contain material boiling above 1000° F. Decant oil from a fluid catalytic converter is one example of a type of material that would be used in decant oil stream 116, but not in aromatic gas oil stream 100.
Hydrotreated Gas Oil
In some embodiments of the present invention, all or a portion of streams 100, 116, 80 and/or 90 may be hydrotreated. As shown in
Aromatic gas oils hydrotreated at any level demonstrate an improved ability to reduce the coking propensity of resid/tar feedstocks as compared to unhydrotreated aromatic gas oil.
Generally, the OCFT increases as the hydrogen uptake of the gas oil increases. Thus, in one embodiment of the present invention, the aromatic gas oil is hydrotreated to give a hydrogen uptake of at least about 200 standard cubic feet per barrel (SCFB), more preferably at least about 300 SCFB, still more preferably at least about 500 SCFB, and still more preferably at least about 1,000 SCFB. In still a further embodiment, the hydrogen uptake by the decant oil is in a range of about 200 to about 1,000 SCFB.
The following examples are presented for purposes of illustration, and are not intended to impose limitations on the scope of the invention.
Instrumentation
Gas oil aromaticity was measured using 13C NMR analysis. Hydrogen uptake by the gas oil was determined by measuring the difference in hydrogen content of the feedstock after passing through the hydrotreater using the following equation:
Hydrogen uptake=ρ·658.5 (ΔH)
where ρ=density (g/cc) of the hydrotreater feed and ΔH=difference in hydrogen content (wt %) of the hydrotreater product and feed.
The coking propensity of each sample resid and resid/gas oil mixture was determined from OCFTs, measured using the coking propensity test method and apparatus described in International Publication No. WO 01/53813, incorporated herein by reference in its entirety for all purposes. The test method measures the propensity of liquid feedstocks to form coke when heat and pressure are applied. The test apparatus comprises a container or reactor outfitted with a heater cartridge having a hot zone for heating liquid feedstock, a liquid thermocouple to measure the temperature of the liquid feedstock, and a heater thermocouple for measuring the temperature of the heater cartridge hot zone. During measurement of coking propensity, a thermocouple located inside the cartridge is controlled at constant temperature. As coke forms or solids deposit on the surface of the heater, an insulating barrier is formed which reduces the power required to maintain the desired constant cartridge temperature. The time to decrease the power required to maintain the heater at the desired temperature determines the propensity for coking of the liquid feedstock.
Sample Preparation
Hydrotreatment of gas oils was carried out using a hydrotreater pilot plant. Gas oils were fractionated in the laboratory at 2 mm Hg in a D-1160 apparatus.
Coking Propensities of Feedstocks Modified with Various Gas Oils
A resid feedstock having physical properties as shown in Table I was tested using the coking propensity apparatus described in International Publication No. WO 01/53813. Also tested were blends consisting of about 80 wt % of the resid with about 20 wt % of each of the gas oils listed below in Table I.
The properties and OCFT data for each sample tested with the coking propensity apparatus are summarized in Table II. Because the OCFT is very sensitive to liquid temperature, the corrected OCFT for each sample is also listed. The corrected OCFT is obtained by using an Arrhenius thermal severity factor to normalize experimental data to a constant level of liquid temperature. As shown below, unmodified resids have much shorter OCFT times, and thus, higher coking propensities, than those modified with 20 Wt % aromatic gas oil or hydrotreated aromatic gas oil.
13C NMR
Coking Propensities of Feedstocks Modified with Fractionated Gas Oils
Gas oils 1 and 3 were each fractionated to produce a 750-850° F. fraction and an 850+° F. fraction. These fractions were mixed with the resid from Example 1 in a proportion of about 80 wt % resid and about 20 wt % gas oil. The properties and OCFT data for these samples are summarized in Table IV.
The data in Table IV demonstrate that the 750-850° F. fraction is more effective than the 850+° F. fraction at slowing coke formation, particularly in the case of hydrotreated gas oil #3.
Coking Propensities of Feedstocks Modified with Fractionated Gas Oils
Gas oil 6, which was less effective at slowing coke formation than the other gas oils tested in Example 1, was fractionated to produce a 750-850° F. fraction and a fraction boiling below 950° F. These fractions were mixed with the resid from Example 1 in a proportion of about 80 wt % resid and about 20 wt % gas oil. The properties and OCFT data for these samples are summarized in Table V.
Table V illustrates results similar to those of Example 2, specifically, that separating out the highest molecular weight fraction of the gas oil makes the gas oil more effective at slowing the onset of coke formation.
The foregoing description of preferred embodiments of this invention is intended to be illustrative and is not intended to impose any limitations on the scope of the invention.
