Patent Application
20240115996
The present disclosure generally relates to methods and systems for reducing nitrogen oxides (NOx) in a heat generation unit using a sour water stripper vapor stream as a selective non-catalytic reduction reagent. More specifically, the present disclosure relates to methods for decreasing NOx emissions generated during the combustion of exhaust gas produced within the operation of a fluid catalytic cracking unit by using sour water stripper off-gas as a selective non-catalytic reduction reagent.
In the hydrocarbon processing industry, the operation of a fluid catalytic cracking unit (FCCU) exhausts regeneration (regen) gas containing two or more of carbon monoxide (CO), hydrogen cyanide (HCN), ammonia (NH3), and NOx gases. To reclaim the energy from the exhaust gas and decrease CO emission, a heat generation unit may be included in the FCCU design or operably connected to the FCCU to combust CO in the regen gas and generate steam. Depending on the operating mode of the FCCU, the regen gas may contain varying concentrations of nitrogen species, such as HCN, NH3, and NOx. In addition to the NOx that may be present in the regen gas, the other nitrogen-containing compounds in the regen gas are sources of thermally-produced NOx in the heat generation unit. In addition to other methods of decreasing NOx emissions, NOx may be reduced using a selective non-catalytic reduction (SNCR) system. However, the use of a SNCR system typically involves the purchase of urea or NH3 and the ability to transport and store the material on site. Further, if NH3 is utilized, additional precautions are required due to its toxicity. Additionally, this stored material is pumped, vaporized/atomized (often with air or steam), and injected into the unit, posing increased operational costs and safety hazards.
There is a need for methods and systems capable of safely and economically reducing nitrogen oxide emissions from a heat generation unit. To address these shortcomings in the art, Applicant has developed methods and systems for decreasing NOx emissions by reducing NOx that is present within an exhaust gas, as well as NOx generated during combustion of the exhaust gas, by using sour water stripper (SWS) off-gas as a selective non-catalytic reduction reagent, to decrease NOx emissions, in accordance with the example embodiments disclosed herein.
Embodiments of methods for reducing NOx in a heat generation unit are provided. In certain embodiments, a method for reducing NOx in a heat generation unit includes the steps of introducing an exhaust gas from a catalytic cracking unit to a combustion zone of a heat generation unit to produce a combusted exhaust gas, introducing a SWS vapor stream from a SWS unit to the heat generation unit at a location after the combustion zone and before a heat recovery zone of the heat generation unit, and allowing the SWS vapor stream to react with the combusted exhaust gas to produce a processed exhaust gas with a decreased NOx content compared to a NOx content when the exhaust gas is processed under similar conditions but without an interaction with the SWS vapor stream. The exhaust gas contains two or more of CO, HCN, NH3, and NOx.
Embodiments of methods for operating a heat generation unit are provided. In certain embodiments, the method for operating a heat generation unit includes the steps of combusting a regen gas stream in a combustion zone of the heat generation unit to produce a combusted regen gas that contains NOx, injecting a SWS vapor stream that contains NH3 as a SNCR reagent into a post-combustion zone of the heat generation unit, and allowing the NH3 of the SWS vapor stream to react with the NOx of the combusted regen gas in the post-combustion zone of the heat generation unit to produce a processed exhaust gas having a decreased NOx content. In certain embodiments, the steps include receiving the regen gas stream from a fluid catalytic cracking unit, wherein the regen gas stream contains CO and one or more nitrogen-containing compounds. In certain embodiments, the one or more nitrogen-containing compounds are selected from the group consisting of: HCN, NH3, and NOx. In certain embodiments, the steps include receiving the SWS vapor stream from a SWS unit, wherein the SWS vapor further contains steam and H2S. The post-combustion zone can be located downstream of the combustion zone and upstream of a heat recovery zone of the heat generation unit.
In certain embodiments, the SWS vapor stream is introduced in at least two or three temperature sections of the heat generation unit. The temperature sections can be defined by an average temperature of the combusted exhaust gas. The temperature sections can be defined by a range of temperature of the combusted exhaust gas. In certain embodiments, the temperature of the combusted exhaust gas in a first temperature section ranges from about 1600° F. to about 1800° F. and the temperature of the combusted exhaust gas in a second temperature section ranges from above 1800° F. to about 2200° F. In certain embodiments, the temperature of the combusted exhaust gas in a first temperature section ranges from about 1600° F. to about 1800° F., the temperature of the combusted exhaust gas in a second temperature section ranges from above 1800° F. to about 1900° F., and the temperature of the combusted exhaust gas in a third temperature section ranges from above 1900° F. to about 1955° F. In some embodiments, the processed exhaust gas contains less than 300 parts per million by volume-dry (ppmvd) of NOx, less than 1 part per million by volume-wet (ppmvw) of CO, and about 20 ppmvd or less of NH3. In some embodiments, the processed exhaust gas contains about 100 ppmvd or less of NOx and about 5 ppmvd or less of NH3. In some embodiments, the decreased NOx content of the processed exhaust gas is at least 30% less than a NOx content of the combusted regen gas.
Embodiments of systems for reducing NOx in a heat generation unit are provided. An embodiment of a heat generation system includes an exhaust gas conduit for conveying exhaust gas from a cracking unit to a furnace unit; the furnace unit containing (i) a combustion zone to receive and facilitate combustion of the exhaust gas to produce combusted exhaust gas, (ii) a post-combustion zone equipped with a plurality of inlets to inject a plurality of SWS vapor streams from a SWS unit into the combusted exhaust gas from the combustion zone to produce the processed exhaust gas, and (iii) a heat recovery zone to capture heat from the processed exhaust gas; and a vent conduit for emission of the processed exhaust gas after passing through the heat recovery zone. In certain embodiments, the plurality of inlets includes at least one inlet disposed in each of at least two or three temperature sections in the post-combustion zone. The temperature sections can be defined by an average temperature of the combusted exhaust gas. The temperature sections can be defined by a range of temperature of the combusted exhaust gas. In certain embodiments, the temperature of the combusted exhaust gas in a first temperature section ranges from about 1600° F. to about 1800° F. and the temperature of the combusted exhaust gas in a second temperature section ranges from above 1800° F. to about 2200° F. In certain embodiments, the temperature of the combusted exhaust gas in a first temperature section ranges from about 1600° F. to about 1800° F., the temperature of the combusted exhaust gas in a second temperature section ranges from above 1800° F. to about 1900° F., and the temperature of the combusted exhaust gas in a third temperature section ranges from above 1900° F. to about 1955° F.
In an embodiment, a system includes a SWS unit configured to generate a SWS vapor stream that contains NH3 and steam. The system includes a CO boiler containing a combustion zone and a post-combustion zone, the post-combustion zone having SNCR nozzles configured to receive and inject a portion of the SWS vapor stream into a combusted exhaust gas from the combustion zone to produce a processed exhaust gas having decreased NOx content. In some embodiments, the system includes a fluid catalytic cracking unit in fluid communication with the CO boiler and configured to provide a regen gas stream to the combustion zone of the CO boiler, and at least the regen gas stream is combusted in the combustion zone to generate the combusted exhaust gas. In some embodiments, a second portion of the SWS vapor stream is combined with the regen gas stream before being combusted together in the combustion zone to generate the combusted exhaust gas. The processed exhaust gas can contain less than 300 ppmvd of NOx, less than 1 ppmvw of CO, and about 20 ppmvd or less of NH3. In some embodiments, the CO boiler is a wall-fired CO boiler or a tangentially-fired CO boiler. In certain embodiments, a molar ratio of NH3 to NOx in the post-combustion zone is between about 1.8 and about 3.1.
In some embodiments of the methods and systems, the cracking unit is a fluid catalytic cracking unit. In some embodiments of the methods and systems, the NOx content in the processed exhaust gas is about thirty percent less than the NOx content when the exhaust gas is processed under similar conditions but without an interaction with the SWS vapor stream. In some embodiments of the methods and systems, the NOx content in the processed exhaust gas is about fifty percent less than the NOx content when the exhaust gas is processed under similar conditions but without an interaction with the SWS vapor stream. In some embodiments of the methods and systems, the NOx content in the processed exhaust gas is about seventy percent less than the NOx content when the exhaust gas is processed under similar conditions but without an interaction with the SWS vapor stream.
Still other aspects and advantages of these example embodiments and other embodiments, are discussed in detail herein. Moreover, it is to be understood that both the foregoing information and the following detailed description provide merely illustrative examples of various aspects and embodiments, and are intended to provide an overview or framework for understanding the nature and character of the claimed aspects and embodiments. Accordingly, these and other objects, along with advantages and features of the present disclosure, will become apparent through reference to the following description and the accompanying drawings. Furthermore, it is to be understood that the features of the various embodiments described herein are not mutually exclusive and may exist in various combinations and permutations.
The accompanying drawings, which are included to provide a further understanding of the embodiments of the present disclosure, are incorporated in and constitute a part of this specification, illustrate embodiments of the present disclosure, and together with the detailed description, serve to explain principles of the embodiments discussed herein. No attempt is made to show structural details of this disclosure in more detail than may be necessary for a fundamental understanding of the embodiments discussed herein and the various ways in which they may be practiced. According to common practice, the various features of the drawings discussed below are not necessarily drawn to scale. Dimensions of various features and elements in the drawings may be expanded or reduced to illustrate embodiments of the disclosure more clearly.
The present disclosure describes various embodiments related to processes, methods, and systems for integrating petrochemical and refinery operations. Further embodiments may be described and disclosed.
In the following description, numerous details are set forth in order to provide a thorough understanding of the various embodiments. In other instances, well-known processes, devices, and systems may not have been described in particular detail in order not to unnecessarily obscure the various embodiments. Additionally, illustrations of the various embodiments may omit certain features or details in order to not obscure the various embodiments.
The description may use the phrases “in some embodiments,” “in various embodiments,” “in an embodiment,” or “in embodiments,” which may each refer to one or more of the same or different embodiments. Furthermore, the terms “comprising,” “including,” “having,” and the like, as used with respect to embodiments of the present disclosure, are synonymous.
The terms “about” or “approximately” are defined as being close to as understood by one of ordinary skill in the art. In one non-limiting embodiment, the terms are defined to be within 10%, preferably within 5%, more preferably within 1%, and most preferably within 0.5%.
The use of the words “a” or “an” when used in conjunction with any of the terms “comprising,” “including,” “containing,” or “having” in the claims or the specification may mean “one,” but are also consistent with the meaning of “one or more,” “at least one,” and “one or more than one.” The terms “wt. %”, “vol. %”, or “mol. %” refer to a weight, volume, or molar percentage of a component, respectively, based on the total weight, the total volume of material, or total moles, that includes the component. In a non-limiting example, 10 grams of a component in 100 grams of the material is 10 wt. % of the component.
The words “comprising” (and any form of comprising, such as “comprise” and “comprises”), “having” (and any form of having, such as “have” and “has”), “including” (and any form of including, such as “includes” and “include”) or “containing” (and any form of containing, such as “contains” and “contain”) are inclusive or open-ended and do not exclude additional, unrecited elements or method steps. The term “NOx” refers to nitrogen oxide (NO), or nitrogen dioxide (NO2), or combinations thereof.
Heat generation units as described here include all types of furnaces and boilers that process exhaust gases by combustion under adequate temperature and residence time to generate heat. Disclosed here is a method for reducing NOx in a heat generation unit that processes exhaust gases containing two or more of CO, HCN, NH3, and NOx generated from a catalytic cracking unit. There are several sources of NOx in a refinery, including regen gas that is an exhaust gas of a cracking unit. The Applicant has determined that the use of a waste stream from a sour water stripper (SWS) as a SNCR reagent can result in significant decreases in NOx emission. Implementation of systems and methods disclosed herein also reduce or avoid significant equipment, operating, and maintenance costs for installation of a SNCR system. In certain embodiments, the heat generation unit can be any thermal oxidizer with a heat recovery system. In certain embodiments, the heat generation unit is a carbon monoxide (CO) boiler used to oxidize CO-rich waste gases typically generated by a catalytic cracking unit. Additionally, the use of a waste stream from a SWS as a SNCR reagent provides an alternative disposition for the waste stream that further minimizes emissions and costs associated with processing waste stream in a fluid catalytic cracking unit operation. The presently disclosed methods are operable to reduce NOx in a heat generation unit by introducing SWS vapor to the heat generation unit at a location after the combustion zone, where the SWS vapor can act as a SNCR reagent. Sour water stripping is used to remove NH3 and H2S from SWS vapor streams generated from distillation, fluid catalytic cracking, catalytic reforming, coker and acid gas removal units, etc. in a refinery. SWS vapor can be mixed with the regen gas, then combusted in a heat generation unit. The presence of NH3 in the SWS vapor has potential to generate a significant quantity of fuel NOx emissions in the heat generation unit. The amount of NOx emission was decreased by relocating a portion of the SWS vapor stream from the combustion zone to the post-combustion zone in the heat generation unit under adequate temperature and residence time conditions, where the SWS vapor acts as a SNCR reagent. In addition to the NOx reduction, there can be a decrease in the H2S emissions by relocation of the SWS vapor stream.
Embodiments of systems for reducing NOx in a heat generation unit are provided. An embodiment of a heat generation system includes an exhaust gas conduit for conveying exhaust gas from a cracking unit to a furnace unit; the furnace unit containing (i) a combustion zone to receive and facilitate combustion of the exhaust gas to produce combusted exhaust gas, (ii) a post-combustion zone equipped with a plurality of inlets to inject a plurality of SWS vapor streams from a SWS unit into the combusted exhaust gas from the combustion zone to produce the processed exhaust gas, and (iii) a heat recovery zone to capture heat from the processed exhaust gas; and a vent conduit for emission of the processed exhaust gas after passing through the heat recovery zone. In certain embodiments, the plurality of inlets includes at least one inlet disposed in each of at least two or three temperature sections in the post-combustion zone. The temperature sections can be defined by an average temperature of the combusted exhaust gas. The temperature sections can be defined by a range of temperature of the combusted exhaust gas. In certain embodiments, the temperature of the combusted exhaust gas in a first temperature section ranges from about 1600° F. (871° C.) to about 1800° F. (982° C.) and the temperature of the combusted exhaust gas in a second temperature section ranges from above 1800° F. to about 2200° F. (1204° C.). In certain embodiments, the temperature of the combusted exhaust gas in a first temperature section ranges from about 1600° F. to about 1800° F., the temperature of the combusted exhaust gas in a second temperature section ranges from above 1800° F. to about 1900° F. (1038° C.), and the temperature of the combusted exhaust gas in a third temperature section ranges from above 1900° F. to about 1955° F. (1068° C.).
Embodiments disclosed here include SNCR processes using SWS vapor as a SNCR reagent for NOx control in two heat generation configurations. In both configurations, some or all of the SWS vapor is mixed with the exhaust gas after the combustion zone, subsequently generating a significantly decreased amount of NOx and H2S emissions.
The heat generation unit 110 is operable to deliver the relocated SWS vapor stream 108 at a location after the combustion zone and before a heat recovery zone, in order to react the combusted exhaust gas with the relocated SWS vapor stream 108 and produce a processed exhaust gas 126 with decreased NOx content compared to NOx content when the exhaust gas is processed under similar conditions, but without the relocated SWS vapor stream 108. In certain embodiments, the processed exhaust gas contains about 10 percent (%) less NOx content compared to the NOx content when the exhaust gas is processed under similar conditions, but without the relocated SWS vapor stream. In certain embodiments, the processed exhaust gas contains about 20% less NOx content compared to the NOx content when the exhaust gas is processed under similar conditions, but without the relocated SWS vapor stream. In certain embodiments, the processed exhaust gas contains about 30% less NOx content compared to the NOx content when the exhaust gas is processed under similar conditions, but without the relocated SWS vapor stream. In certain embodiments, the processed exhaust gas contains about 40% less NOx content compared to the NOx content when the exhaust gas is processed under similar conditions, but without the relocated SWS vapor stream. In certain embodiments, the processed exhaust gas contains about 50% or less NOx content compared to the NOx content when the exhaust gas is processed under similar conditions, but without the relocated SWS vapor stream. In certain embodiments, the processed exhaust gas contains about 70% or less NOx content compared to NOx content when the exhaust gas is processed under similar conditions, but without the relocated SWS vapor stream. The example system 100 may also include an additional emissions control unit 112 operable to remove other pollutants present in the processed exhaust gas 126.
In certain embodiments, the processed exhaust gas 126 contains less than 1 part per million by volume-wet (ppmvw) of CO. In certain embodiments, the processed exhaust gas contains less than 350 parts per million by volume, dry (ppmvd) of NOx. The processed exhaust gas may contain less than 340 ppmvd of NOx, less than 330 ppmvd of NOx, or less than 320 ppmvd of NOx. In some embodiments, the processed exhaust gas contains less than 310 ppmvd of NOx or about 305 ppmvd of NOx. In some embodiments, the processed exhaust gas contains less than 310 ppmvd of NOx or about 305 ppmvd of NOx. In some embodiments, the processed exhaust gas contains less than 300 ppmvd of NOx, less than 275 ppmvd of NOx, less than 250 ppmvd of NOx, or less than 200 ppmvd of NOx. In some embodiments, the processed exhaust gas contains less than 190 ppmvd of NOx, less than 175 ppmvd of NOx, less than 150 ppmvd of NOx, or less than 125 ppmvd of NOx. In some embodiments, the processed exhaust gas contains less than 100 ppmvd of NOx or less than 75 ppmvd of NOx.
The example embodiment of the system 100 also includes a refinery sour water 114 fed to a first SWS 116, which may come from, but not limited to, a connection with a distillation unit, a fluid catalytic cracking unit, or a catalytic reforming unit in a refinery to produce a SWS stream 118 and a waste gas stream 124. The SWS stream 118 is a partially stripped and rectified sour water stream. The first SWS 116 functions to remove H2S in waste gas stream 124 while segregating NH3 in the liquid phase SWS stream 118. The waste gas stream 124 from the first SWS 116 is supplied to a Claus unit or other sulfur processing units. The liquid phase from the first SWS 116 is supplied to a second SWS 122 to produce a stripped sour water 120 and the SWS vapor stream 106. In certain embodiments, the SWS vapor streams 106 and 108 primarily contain saturated steam and NH3. The SWS vapor streams can be produced from an unquenched second stage SWS overhead with trace hydrocarbon and sulfur species and can be directed for SNCR reactions in furnaces and boilers. The SWS vapor can be injected at multiple locations inside the heat generation unit to provide a good distribution of NH3.
The examples provided below illustrate selected aspects of the various embodiments of systems and methods of utilizing SWS vapor as a SNCR reagent in a heat generation unit.
Two configurations of the heat generation unit were analyzed. CFD-based evaluation performed on two typical styles of CO boilers (COB) demonstrated that significant NOx reduction was obtained by relocating SWS vapor from the combustion zone to downstream SNCR ports in the boilers. NOx reduction is dependent on the regen gas temperature, available residence time, and the mixing of SNCR reagent and regen gas. NOx reduction is also impacted by the amount of SWS vapor that was directed to the SCNR ports, with higher NOx reduction seen with higher SWS rates to the SNCR ports. There was also significant H2S oxidation at SNCR zone temperatures.
The first configuration includes a wall-fired boiler as an illustrative example of a heat generation unit. The wall-fired CO boiler includes fuel gas burners that are fired horizontally from the end of the boiler, while regen gas mixed with SWS vapor is injected into the combustion zone from the top of the boiler. The CFD evaluation included the relocation of a portion of the SWS vapor stream to SNCR ports located in the post-combustion zone, instead of this portion of the SWS vapor stream being combined with the regen gas and combusted in the combustion zone of the CO boiler. Different SWS vapor stream flow rates to the combustion and SNCR zones were evaluated through the CFD simulations in order to determine optimum operation for NOx reduction.
The second configuration includes a tangentially-fired CO boiler as an illustrative example of a heat generation unit. In this style of CO boiler, the regen gas ports and the fuel gas burners are located at the corners of the CO boiler, with the burner region of the boiler lined with a refractory material and the upper region of the boiler enclosed with bare waterwall tubes. In this configuration, a portion of the SWS vapor stream was relocated to SNCR ports installed above the burner region, where conditions were more favorable for SNCR chemistry, instead of this portion of the SWS vapor stream being combined with the regen gas and combusted in the combustion zone of the CO boiler. Different SWS vapor stream flow rates to the regen gas and SNCR ports were evaluated in order to optimize operation for NOx reduction.
The CFD model was a three-dimensional, reacting CFD model from Reaction Engineering International that has been extensively utilized to simulate gas-fired combustion applications that demand an accurate treatment of chemistry and turbulence-chemistry interactions.
Similarly, for the tangentially fired CO boiler, baseline predicted gas temperatures, CO concentrations, and NOx concentrations before any proposed modifications were modeled. Based on predicted temperatures and CO concentrations, SNCR ports were simulated at a suitable location above the upper burner elevation. In this evaluation, a fixed portion of the total SWS vapor was mixed with the regen gas in the combustion zone, and incrementally increased SWS vapor flow rates through the SNCR ports were simulated, including low (SNCR 1), median (SNCR 2) and high (SNCR 3) SWS vapor flow rates. Table 1 presents the flow rate and other conditions for the baseline and three case analysis. For the modeling with low SWS vapor flow rate (SNCR 1), the processed exhaust gas contains about 50% lower NOx content compared to the NOx content when the exhaust gas is processed under similar conditions, but without the relocated SWS vapor stream. For the modeling with median SWS vapor flow rate (SNCR 2), the processed exhaust gas contains about 65% lower NOx content compared to the NOx content when the exhaust gas is processed under similar conditions, but without the relocated SWS vapor stream. For the modeling with high SWS vapor flow rate (SNCR 3), the processed exhaust gas contains about 73% lower NOx content compared to the NOx content when the exhaust gas is processed under similar conditions, but without the relocated SWS vapor stream.
The SWS vapor may also contain H2S and the relocation of the SWS vapor stream from the combustion zone to the SNCR ports in a CO boiler raises the potential concern of increased H2S emissions. A preliminary evaluation was carried out to evaluate the potential for increased H2S emissions. A series of isothermal plug flow calculations were carried out to evaluate the rate of oxidation of H2S over a relevant temperature range. The results, as shown in
Results of a CFD-based evaluation performed on two typical styles of CO boilers show that significant decreases in NOx can be obtained by relocating SWS vapor from the combustion zone to downstream SNCR ports in the boiler. NOx reduction is dependent on the flue gas temperature, available residence time, and the mixing of reagent and flue gas. NOx reduction was also impacted by the amount of SWS vapor that was directed to the SCNR ports, with greater NOx reduction seen with higher SWS rates to the SNCR ports. The decrease in NOx may be limited, however, by how much NH3 slip can be tolerated, as the modeling also showed increased NH3 slip at higher SWS vapor rates to the SCNR ports, especially for boilers that have colder operating temperatures. Detailed chemical kinetics calculations to evaluate the impact of temperature on H2S oxidation indicate that there is significant H2S oxidation at typical SNCR zone temperatures. However, impacts of mixing also needs to be considered, ideally within a CFD simulation, to obtain accurate predictions of the impact of SWS vapor stream relocation on H2S emissions.
Initially, two baseline cases were developed to calibrate the CFD-based evaluation of a CO boiler (COB1) to actual operating conditions of COB1 using PI data and stack test data. For this example embodiment, the CFD model includes two COBs and extends to the steam generation bank outlet, where the expected gas temperature is well-below the reaction/oxidation temperatures of the species in question. The first baseline case represents a typical partial burn operation with SWS vapor split between COB1 and COB2. The process basis is presented in Table 2. SWS vapor flow rate is the balance of total flow after deducting the expected usage by COB2 NOx reduction facility. The decrease in NOx emissions is relative to the baseline and adjusted for SWS vapor flow difference between the cases. As used herein, the unit “MMBtu/hr” refers to millions of British Thermal Units per hour, and the unit “MMSCFD” refers to millions of standard cubic feet per day.
The second baseline case represents a typical partial burn operation with nearly identical regen gas flow and compositions, combustion air flow, boiler steam make, and burner fuel gas flow as the first baseline case. The only difference was that the SWS vapor was not delivered to COB 1 and instead was entirely provided to COB2. In both of these baseline cases, the SWS vapor was supplied in the combustion zone of the boiler.
When the combined HCN and NH3 concentrations of 350 ppmvd in the regen gas was used, which is at the low end of the range as determined by prior operating data analysis, both baseline cases match the stack test readings reasonably well. The CFD modeling yielded a CO concentration of less than 1 ppm for Baseline case 1 and Baseline Case 2 (without SWS vapor), respectively, at model exit, which is consistent with the CO readings of zero from a continuous emission monitoring system (CEMS). The CFD modeling yielded a NOx emission of about 172 ppmv for the Baseline Case 1 at the model exit, aligning with the between 151 ppmv and 157 ppmv NOx emission reported in stack test. The CFD modeling yielded a NOx emission of 109 ppmv for the Baseline Case 2 (without SWS vapor) at the model exit, consistent with 117 ppmv reported in stack test for the Baseline Case 1. The CFD modeling yielded a 0.1 ppmv of NH3 and HCN slip at model exit for both baselines. The model revealed that the high NOx concentration is laden in the annulus surrounding the center fire ball to some extent, where the CO concentration is relatively high.
In test case for use of SWS vapor as a SNCR agent, some of the NH3-laden SWS vapor, which is pre-mixed with the regen gas before being injected into primary combustion zone via CO burners, is instead re-routed to cooler locations (namely SNCR zone) downstream of the combustion zone in the COB1 furnace. The SNCR nozzles are located in the wall boxes of the furnace water walls. Rerouting SWS vapor has several positive impacts on NOx emissions. It eliminates a large source of NOx precursors from being converted to NOx in the highest temperature zone (primary combustion zone) of the furnace and provides the NOx reduction reagent (NH3) to destroy the NOx, including NOx produced in the combustion zone, via SNCR chemistry.
The amount of SWS vapor, which can be routed to COB1 SNCR zone, depends on the SWS vapor consumption at COB2 SNCR, stack NOx, and the acceptable levels of NH3 slip for long term reliable operation. For approximately 85% of the time, the SWS vapor contains sufficient NH3 for the SNCR demands of both COB1 and COB2 during the normal operation (partial burn mode). Other embodiments may include a supplemental NH3 system, such as an NH3 storage tank, an NH3 vaporization/mixing/distribution skid, and associated instrument and piping.
The SNCR design for COB1 includes a total of four SNCR wall injectors installed in the water wall, with two injectors installed in a first side wall, and two injectors installed in the same locations of the opposite side wall. All injectors are to be positioned horizontally without tilt and yawn angles for this example embodiment. The injector size is nominal 2 inch schedule (SCH) 80 piping and is uniform for all four wall injectors for this example embodiment.
For this example embodiment, the SWS vapor stream delivered to COB1 can be split into two streams. The existing SWS vapor stream injecting to the regen gas line will remain. A new SNCR supply line is diverted from the existing SWS line upstream of the existing SWS vapor injection point. This line provides the reagent to the SNCR injectors of COB1. The injectors can be steam purged to prevent them from plugging and overheating when the SNCR system is out of service. The purge steam can also provide a minimum flow to the SNCR nozzles in order to achieve a required nozzle exit velocity in the case of low SWS vapor flow. A CFD case was run to verify the design concept, optimize the SNCR injector locations, and quantify the NOx reduction rate and NH3 slip.
For this example embodiment, a portion of the SWS vapor stream previously routed to the primary combustion zone of COB1 is rerouted to the SNCR injectors to maintain a normalized stoichiometric ratio (NSR) of approximately 2 at the SNCR zone of COB1. NSR is defined as the molar ratio of NH3 to NOx at the SNCR inlet. The portion of the SWS vapor stream routed to COB1 is the balance of total SWS vapor stream less the amount consumed at COB2 to maximize COB2 SNCR performance. The amount of NOx is decreased to 102 ppmvd, which represents a 45% lower NOx content relative to the model baseline level of 185 ppmvd, or represents a 35% lower NOx content relative to the COB1 stack test level of 157 ppmvd. The model predicted an average NH3 slip of 4 ppmvd and a CO emission of less than 1 ppmvd. SNCR zone efficiency is 36% (based on the NOx concentration at SNCR zone inlet). SNCR zone efficiency represents the percentage of NOx that is reduced due to the SNCR reaction. The total decrease in NOx content is 45% relative to the baseline case due to the additional NOx reduction as a result of the relocation of part of the SWS vapor stream to the SNCR injectors.
As shown, the case involving relocating a portion of the SWS vapor stream to serve as the SNCR reagent (case SNCR 1) results in significant decrease in NOx emissions of 45% relative to the model baseline level.
Another example embodiment of a system with COB1 and COB2 was subject to CFD modeling following relocation of a portion of the SWS vapor stream to serve as a SNCR reagent. Three configurations were evaluated, and the results are presented in Table 4. In the baseline configuration, 50% of the SWS vapor stream from the SWS unit is supplied to each of the COB1 and COB2 (an Alcorn refractory wall furnace). The 50% of the SWS vapor stream routed to COB2 is supplied as a part of the exhaust gas in the combustion zone of the furnace in the baseline configuration. In the first SNCR configuration (SNCR1_100% SWS), 50% of the SWS vapor stream from the SWS unit is supplied to each of COB1 and COB2, and the entirety of the SWS vapor stream routed to COB2 is injected through SNCR injectors into the combusted exhaust gas in the post-combustion zone. In the second SNCR configuration (SNCR2_50% SWS), 50% of the SWS vapor stream from the SWS unit is supplied to each of COB1 and COB2, where half of the SWS vapor stream supplied to the COB2 is supplied to COB2 in the combustion zone and the other half is injected through SNCR injectors into the combusted exhaust gas in the post-combustion zone of COB2. In the third SNCR configuration (SNCR3_DSWS_50% SWS), none of the SWS vapor stream from the SWS unit is supplied to COB1 and the entirety of SWS vapor stream from the SWS unit is instead supplied only to COB2, where about 50% of the SWS vapor stream delivered to COB2 is supplied as a part of the exhaust gas in the combustion zone of the furnace, and the remaining about 50% of the SWS vapor stream delivered to COB2 is injected through SNCR injectors into the combusted exhaust gas in the post-combustion zone. The results from the baseline and these three configurations are provided in Table 4.
For this example embodiment, the regen gas contains HCN, NOx, and NH3. In this example embodiment, the SWS vapor stream contains about 1.2 wt. % of NH3 and 98.8 wt. % steam. This composition of SWS vapor stream and NH3/NOx ratio is typical for a steam-vaporized NH3 injection SNCR system. Relocation of the SWS vapor stream away from the primary combustion zone has a significant impact on diminishing NOx formation. Piping was modeled to route all or part of the SWS vapor away from the combustion zone by installation of eight 2 inch SNCR nozzles to inject SWS vapor as SNCR reagent and two control valves to control the SWS vapor split between regen gas line and SNCR nozzles.
In the first configuration, the NOx emission decreased to about 42 ppmv, the CO emission was less than 1 ppmv, and the NH3 slip was about 4 ppmv. In the second configuration, the NOx emission decreased to about 101 ppmv, the CO emission was less than 1 ppmv, and the NH3 slip was about 2 ppmv. In the third configuration, the NOx emission was decreased to about 69 ppmv, the CO emission was less than 1 ppmv, and the NH3 slip was about 21 ppmv.
As such, this example indicates that significant NOx emissions reduction is possible when SWS vapor is used as a SNCR reagent. The NH3 slip was small and the conditions for SNCR activity and NOx destruction was optimum in COB2. The CO emission was less than 1 ppmv, as conditions in the furnace/boiler were sufficient for continued CO destruction.
When ranges are disclosed herein, ranges from any lower limit may be combined with any upper limit to recite a range not explicitly recited, as well as, ranges from any lower limit may be combined with any other lower limit to recite a range not explicitly recited, in the same way, ranges from any upper limit may be combined with any other upper limit to recite a range not explicitly recited. Additionally, reference to values stated in ranges includes each and every value within that range, even though not explicitly recited. Thus, every point or individual value may serve as its own lower or upper limit combined with any other point or individual value or any other lower or upper limit, to recite a range not explicitly recited.
The present application claims priority to and the benefit of U.S. Provisional Application No. 63/378,821, filed Oct. 7, 2022, titled “Methods and Systems for Reducing Nitrogen Oxide Emissions in a Heat Generation Unit using Sour Water Stripper Vapor,” the disclosure of which is incorporated herein by reference in its entirety for all purposes.
Other objects, features and advantages of the disclosure will become apparent from the foregoing drawings, detailed description, and examples. These drawings, detailed description, and examples, while indicating specific embodiments of the disclosure, are given by way of illustration only and are not meant to be limiting. In further embodiments, features from specific embodiments may be combined with features from other embodiments. For example, features from one embodiment may be combined with features from any of the other embodiments. In further embodiments, additional features may be added to the specific embodiments described herein. It should be understood that although the disclosure contains certain aspects, embodiments, and optional features, modification, improvement, or variation of such aspects, embodiments, and optional features can be resorted to by those skilled in the art, and that such modification, improvement, or variation is considered to be within the scope of this disclosure.
The present application claims priority to and the benefit of U.S. Provisional Application No. 63/378,821, filed Oct. 7, 2022, titled “Methods and Systems for Reducing Nitrogen Oxide Emissions in a Heat Generation Unit using Sour Water Stripper Vapor,” the disclosure of which is incorporated herein by reference in its entirety for all purposes.
| Number | Date | Country | |
|---|---|---|---|
| 63378821 | Oct 2022 | US |
