Measuring and testing – Gas analysis – Solid content of gas
Reexamination Certificate
1998-02-13
2001-12-04
Williams, Hezron (Department: 2856)
Measuring and testing
Gas analysis
Solid content of gas
C073S863210, C073S864810, C073S023310
Reexamination Certificate
active
06324895
ABSTRACT:
FIELD OF THE INVENTION
The present invention relates to measuring the character of particulate matter in a gas, and more particularly to measuring the character of particulate matter in a gas stream before entering a turbine.
BACKGROUND OF THE INVENTION
Methods and apparatus for measuring the concentration of particulate matter in a gas are well known. U.S. Pat. Nos. 4,531,402 and 5,571,945 describe such methods and devices, although they employ rather complex and costly systems. Consequently, these systems are not feasible or practical for use in all scenarios or for continuous or semi-continuous use.
Catalytic cracking is the backbone of many refineries. It converts heavy hydrocarbon feeds (gasoils) into lighter products by catalytically cracking large molecules into smaller molecules. Catalytic cracking operates at low pressures, without hydrogen addition, in contrast to hydrocracking, which operates at high hydrogen partial pressures.
In fluidized catalytic cracking (FCC), the cracking catalyst, having an average particle size of about 50-150 microns, circulates between a cracking reactor (typically, a riser reactor) and a catalyst regenerator. In the reactor, the gasoil feed contacts the heated catalyst that exits the regenerator section. This hot catalyst vaporizes and cracks the feed at approximately 425° C.-600° C.
The cracking reaction deposits carbonaceous hydrocarbons, or coke, on the cracking catalyst, thereby partially deactivating the active zeolite sites on the catalyst. The cracked products are separated from the coked catalyst in a disengager section, typically by means of a cyclone system. The separated coked catalyst is then stripped of volatiles, generally by contact with steam, and this stripped catalyst is then regenerated within the regenerator through oxidation with oxygen containing gas, usually air, to burn coke from the catalyst.
This regeneration step restores the activity of the cracking catalyst and simultaneously heats the catalyst to approximately 500° C.-900° C. This heated catalyst is recycled to the cracking reactor to catalytically crack the incoming gasoil feed. A flue gas which is formed by burning the coke in the regenerator is usually treated for removal of particulates and sometimes for conversion of carbon monoxide, after which the flue gas is normally discharged into the atmosphere. Prior to discharge, however, a portion of the energy contained in the flue gas stream can be recovered by using a power recovery turbine.
To be profitable, modern FCC units must run at high throughput, and run for extended periods of time, typically more than one year between shutdowns. Much of the output of the FCC unit is further processed in downstream operating units. A significant fraction of a refinery's gasoline pool is usually derived directly from the FCC unit. It is important that the unit operate reliably for years, and be able to accommodate a variety of gasoil feeds, including very heavy gasoil feeds. The unit must operate without exceeding emissions limits on pollutants or particulates. The cracking catalyst is relatively expensive, and most units have several hundred tons of catalyst in inventory within the FCC unit at one time. Most FCC units circulate tons of catalyst per minute, the large circulation being necessary because the feed rates are large; indeed, roughly five tons of catalyst are required to crack every ton of oil.
If these large amounts of catalyst are not removed from cracked products exiting the reactor section of the FCC unit, the heavy hydrocarbon products become contaminated with catalyst, particularly the smaller particle size catalytic materials, or “fines.” These fines must also be removed from the flue gas that is discharged from the regenerator. Any catalyst not recovered by the cyclone separation system within the regenerator stays associated with the flue gas, unless an electrostatic precipitator, bag house, or some sort of removal stage is added. The amount of fines in most FCC flue gas streams exiting the regenerator is enough to cause severe erosion of the blades of the power recovery turbine if one is used to recover some of the energy in the regenerator flue gas stream.
These solid catalytic fines that exit the regenerator are entrained in the regenerator flue gas stream and are exceedingly difficult to remove, as evidenced by their passing through several stages of highly efficient cyclones. These fines are very small; typically, most of the fines are below 40 microns and some under 5 microns.
Recovery of these catalyst fines has been a challenge since the initial use of FCC units. Refineries with large FCC units typically use 6-8 primary and 6-8 secondary cyclones in their FCC regenerators, and are limited due to mechanical constraints and concerns of excessive pressure drops. This series of cyclones inherently allows a large amount of catalyst fines to pass out with the regenerator flue gas. This material must be removed from the flue gas prior to discharge to the atmosphere or passage through a power recovery turbine.
Generally, a third stage separator is installed upstream of the turbine to reduce the quantity of catalyst fines in the fluid stream to thereby protect the turbine blades, or permit discharge of flue gas to the air. When a third stage separator is used, a fourth stage separator is typically used to process the underflow from the third stage separator.
Accordingly, the amount and size of catalyst fines that can cause damage to the turbine is limited by the use of inertial separating devices upstream of the turbine. These inertial separators are also subject to erosion and other modes of damage that reduce their efficiency. It is, therefore, desirable to provide a device that can be used to monitor the condition of the inertial separators that are used to protect the turbine.
The most damaging particles that enter the turbine are those that are greater than five microns in diameter. These are normally removed by a well designed, efficient, inertial separating system. Therefore, their presence at the inlet to the turbine is indicative of some degree of failure of the inertial separator system.
Current methods of determining the amount of potentially damaging particles entering the turbine have attendant drawbacks. Optical devices measure the amount of light scattered by the particulates in the flue gas. These require either sample conditioning or probe cooling to protect the delicate optical devices. Optical devices also require frequent cleaning of the optics and are more sensitive to the smaller particles than they are to the larger, more damaging particles. It is, therefore, desirable to provide an apparatus for measuring the amount of erosive material in a gas stream that is reliable, relatively inexpensive to operate and maintain, sensitive to relatively large particles and can withstand relatively harsh environmental conditions of the gas stream.
Catalytic cracking units are operated continuously for periods of up to five years. During this time, the unit might experience several periods of abnormal operation, or upsets. If these upsets cause excessive catalyst losses or cause the third stage separator to lose efficiency, then they can also cause accelerated wear of the power recovery turbine blades. Batch sampling usually misses these upsets because the unit is operated smoothly during scheduled testing. To predict the amount of wear in a power recovery turbine, it is important to know the total cumulative exposure to particles larger than about 10 microns. This information can only be obtained with a sampling system that is in continuous or at least semi-continuous operation, where the actual sampling time is at least 10 times the sampling recovery time and where the off-line time for sample recovery is relatively short.
Barrier filter devices extract a portion of the flue gas and pass the sample through a filter or liquid impinger to collect the particulates in the gas stream. The recovered material must then be analyzed to determine the amount of large particles in the sample. Th
Chitnis Girish K.
Freeman Brent David
Lemon, Jr. Edward A.
Mazzocato Lisa
McGovern Stephen J.
Fayyaz Nashmiya
Mobil Oil Corporation
Purwin Paul E.
Wang Joseph C.
Williams Hezron
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