US3463613A - Hydrocarbon analyzer comprising stabilized cool flame generator with servo-positioned flame front - Google Patents

Hydrocarbon analyzer comprising stabilized cool flame generator with servo-positioned flame front Download PDF

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US3463613A
US3463613A US471670A US47167065A US3463613A US 3463613 A US3463613 A US 3463613A US 471670 A US471670 A US 471670A US 47167065 A US47167065 A US 47167065A US 3463613 A US3463613 A US 3463613A
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hydrocarbon
flame
combustion
composition
pressure
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US471670A
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Ellsworth R Fenske
James H Mclaughlin
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Universal Oil Products Co
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Universal Oil Products Co
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Priority to US471670A priority Critical patent/US3463613A/en
Priority to IL26079A priority patent/IL26079A/en
Priority to GB29899/66A priority patent/GB1084844A/en
Priority to FR68704A priority patent/FR1486188A/en
Priority to AT659866A priority patent/AT286941B/en
Priority to ES0328961A priority patent/ES328961A1/en
Priority to DE1673172A priority patent/DE1673172C3/en
Priority to NO163886A priority patent/NO117052B/no
Priority to DK362566AA priority patent/DK120669B/en
Priority to NL666609823A priority patent/NL144736B/en
Priority to BR181272/66A priority patent/BR6681272D0/en
Priority to SE09596/66A priority patent/SE335806B/xx
Priority to CH1020866A priority patent/CH492219A/en
Priority to FI661876A priority patent/FI47934C/en
Priority to JP4586466A priority patent/JPS4513519B1/ja
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    • G—PHYSICS
    • G01—MEASURING; TESTING
    • G01N—INVESTIGATING OR ANALYSING MATERIALS BY DETERMINING THEIR CHEMICAL OR PHYSICAL PROPERTIES
    • G01N21/00—Investigating or analysing materials by the use of optical means, i.e. using sub-millimetre waves, infrared, visible or ultraviolet light
    • G01N21/62—Systems in which the material investigated is excited whereby it emits light or causes a change in wavelength of the incident light
    • G01N21/71—Systems in which the material investigated is excited whereby it emits light or causes a change in wavelength of the incident light thermally excited
    • G01N21/72—Systems in which the material investigated is excited whereby it emits light or causes a change in wavelength of the incident light thermally excited using flame burners
    • G—PHYSICS
    • G01—MEASURING; TESTING
    • G01N—INVESTIGATING OR ANALYSING MATERIALS BY DETERMINING THEIR CHEMICAL OR PHYSICAL PROPERTIES
    • G01N33/00—Investigating or analysing materials by specific methods not covered by groups G01N1/00 - G01N31/00
    • G01N33/26—Oils; Viscous liquids; Paints; Inks
    • G01N33/28—Oils, i.e. hydrocarbon liquids
    • G01N33/2829—Mixtures of fuels
    • Y—GENERAL TAGGING OF NEW TECHNOLOGICAL DEVELOPMENTS; GENERAL TAGGING OF CROSS-SECTIONAL TECHNOLOGIES SPANNING OVER SEVERAL SECTIONS OF THE IPC; TECHNICAL SUBJECTS COVERED BY FORMER USPC CROSS-REFERENCE ART COLLECTIONS [XRACs] AND DIGESTS
    • Y10—TECHNICAL SUBJECTS COVERED BY FORMER USPC
    • Y10S—TECHNICAL SUBJECTS COVERED BY FORMER USPC CROSS-REFERENCE ART COLLECTIONS [XRACs] AND DIGESTS
    • Y10S208/00—Mineral oils: processes and products
    • Y10S208/01—Automatic control
    • Y—GENERAL TAGGING OF NEW TECHNOLOGICAL DEVELOPMENTS; GENERAL TAGGING OF CROSS-SECTIONAL TECHNOLOGIES SPANNING OVER SEVERAL SECTIONS OF THE IPC; TECHNICAL SUBJECTS COVERED BY FORMER USPC CROSS-REFERENCE ART COLLECTIONS [XRACs] AND DIGESTS
    • Y10—TECHNICAL SUBJECTS COVERED BY FORMER USPC
    • Y10T—TECHNICAL SUBJECTS COVERED BY FORMER US CLASSIFICATION
    • Y10T436/00—Chemistry: analytical and immunological testing
    • Y10T436/12—Condition responsive control
    • Y—GENERAL TAGGING OF NEW TECHNOLOGICAL DEVELOPMENTS; GENERAL TAGGING OF CROSS-SECTIONAL TECHNOLOGIES SPANNING OVER SEVERAL SECTIONS OF THE IPC; TECHNICAL SUBJECTS COVERED BY FORMER USPC CROSS-REFERENCE ART COLLECTIONS [XRACs] AND DIGESTS
    • Y10—TECHNICAL SUBJECTS COVERED BY FORMER USPC
    • Y10T—TECHNICAL SUBJECTS COVERED BY FORMER US CLASSIFICATION
    • Y10T436/00—Chemistry: analytical and immunological testing
    • Y10T436/21—Hydrocarbon
    • Y10T436/214—Acyclic [e.g., methane, octane, isoparaffin, etc.]

Definitions

  • composition of a hydrocarbon containing sample mixture such as a gasoline fraction-is determined by burning said mixture in a combustion tube under conditions to generate therein a stabilized cool flame.
  • the position of the flame front is automatically detected and used to develop a control signal which, in turn, is used to vary a combustion parameter, such as pressure, temperature or air flow, in a manner to immobilize the flame front regardless of changes in composition of the sample mixture.
  • a combustion parameter such as pressure, temperature or air flow
  • the change in such combustion parameter required to immobilize the flame following a change of sample composition is correlatable with such composition change.
  • a suitable readout device may be calibrated in terms of the desired identifying characteristic of the hydrocarbon-containing sample, as, for example, octane number.
  • This invention relates to the determination of the composition of hydrocarbon-containing mixtures or hydrocarbon fractions and more particularly to methods and apparatus for analyzing hydrocarbon mixtures which utilize a stabilized cool flame generator.
  • Our apparatus is useful not only in the laboratory but more especially as a continuous process stream analyzer adapted for on-site use in a petroleum refinery or chemical plant in performing indicating, recording and/or process control functions.
  • cool flame are observed after an induction period.
  • These cool flames are light emissions accompanied by the evolution of mild amounts of heat less than the heat of combustion.
  • cool flames may quench or after a second induction period, the mixture may ignite spontaneously and explode; this latterphenomenon is known as autoignition.
  • autoignition It is also possible to so regulate the combustion parameters that a continuous or stabilized cool flame results e.g., a flame which neither quenches nor develops into the autoignition phase but rather manifests itself as a stable, well-defined flame front. Baruseh and Payne, In-
  • the generation and maintenance of a continuous or stabilized cool flame is dependent on a number of operating parameters as well as the dimensions of the specific apparatus utilized therefor. These include the following:
  • combustion tube such as shape of cross-section, cross-sectional area, length, degree of taper if any, etc.
  • Burner nozzle design such as cross-sectional areas of hydrocarbon and oxidizer inlets, volume and shape of mixing chamber, etc.
  • Our invention therefor relates to methods and apparatus for analyzing hydrocarbon containing mixtures based on the generation of a stabilized cool flame.
  • the present invention distinguishes over the prior art in at least four important respects: (1) the partial combustion is effected under superatmospheric pressure: (2) the provision of means to sense the physical position of the flame; (3) the use of such flame-positio information to reset a combustion parameter such that the flame front is immobilized; and (4) the provision of means to indicate, display or otherwise read out such combustion parameter which, as indicated above, is correlata'ble with the hydrocarbon composition.
  • our invention embodies a hydrocarbon analyzer comprising a combustion chamber; means for generating a stabilized cool flame Within the combustion chamber utilizing as fuel therefor a hydrocarbon-containing mixture to be analyzed; means for sensing the physical position of said flame within the combustion chamber; control means coupled to said sensing means and to said generating means adapted to adjust a combustion parameter in a manner to maintain the physical position of the flame constant relative to the combustion chamber; and readout means developing a signal responsive to said combustion parameter which in turn provides a measure of hydrocarbon composition.
  • this invention is directed to a hydrocarbon analyzer comprising a combustion chamber; means for generating a stabilized cool flame within the combustion chamber including burner means, a hydrocarbon inlet line connecting with the burner means, and means for varying the preseure within said combustion chamber; means for sensing the physical position of the stabilized cool flame within the combustion chamber, said sensing means being spaced a predetermined distance from the burner means; feedback control means coupled to said sensing means and to said pressure-varying means adapted to adjust combustion pressure in a manner to immobilize said flame with respect to the burner means, regardless of the changes in the composition of the hydrocarbon charged through the hydrocarbon inlet line; and readout means connecting with the combustion chamber and developing a signal responsive to the combustion pressure which in turn provides a measure of hydrocarbon composition.
  • our invention relates to a method of detecting changes in composition of a hydrocarbon containing mixture which comprises introducing a sample stream of said mixture and a stream of oxygen-containing gas into one end of a combustion zone maintained at elevated temperature and under superatmospheric pressure; therein partially oxidizing the hydrocarbon constituents of said sample under conditions to generate in said zone a stabilized cool flame characterized by a relatively narrow, well-defined flame front spaced from said one end; sensing the position of said front relative to said one end and developing therefrom a control signal; utilizing said control signal to adjust a combustion parameter such as combustion pressure, sample flow rate, oxygen-containing gas flow rate, or induction zone temperature in a manner to immobilize said flame front relative to said one end regardless of changes in hydrocarbon composition; and sensing said adjusted parameter and developing therefrom an output signal responsive to changes in sample composition.
  • a combustion parameter such as combustion pressure, sample flow rate, oxygen-containing gas flow rate, or induction zone temperature
  • a further embodiment of this invention embraces a method for detecting changes in composition of a normally liquid hydrocarbon fraction which comprises introducing a preheated vaporized stream of said hydrocarbon fraction and a preheated stream of air into one end of a combustion zone maintained at elevated temperature and under superatmospheric pressure; therein partially oxidizing said hydrocarbon fraction under conditions to generate in said zone a stabilized cool flame characterized by a relatively narrow, well-defined flame front spaced from said one end; sensing the position of the flame front relative to said one end and developing therefrom a control signal; varying the pressure of said combustion zone responsive to said control signal in a manner to immobilize said flame front relative to said one end regardless of changes in hydrocarbon composition; and sensing said combustion pressure and developing therefrom an output signal responsive to changes in said hydrocarbon composition.
  • hydrocarbon analyzer or hydrocarbon analysis do not mean a compound-by-compound analysis of the type presented by instruments such as mass spectrometers or vapor phase chromatographs; rather the analysis is represented by a continuous, or substantially continuous, output signal which is responsive to and indicative of hydrocarbon composition and, more specifically, is empirically correlatable With one or more conventional identifications or specifications of petroleum products such as Reid vapor pressure, ASTM or Engler distillations, and, for motor fuels, knock characteristics such as research octane number, motor octane number, and the like.
  • the specific nature of the correlation is a function of composition and carbon number and is further influenced by the presence or absence of paraflins, isoparafiins, olefins, diolefins and polyolefins, aromatics, long chain substituted aromatics, polynuclear aromatics, etc.
  • the present analyzer will be calibrated for a particular hydrocarbon blend or charge stock and relatively small composition deviations therefrom can be accounted for by linear extrapolation; for example, a different calibration may be found necessary when the hydrocarbon sample is changed from catalytically reformed gasoline to catalytically cracked gasoline.
  • output signa or signal developed by the readout means is to be construed in its broadest meaningful sense and includes analog signals of all types such as amplitude-modulated, phase-modulated, or frequencymodulated electrical signals or pressure signals by conventional pneumatic transmission media, as well as digital representations of the foregoing.
  • the output signal is further intended to include simple mechanical motion or displacement of a transducer member (whether or not mechanically, electrically or pneumatically coupled to a visual display means such as an indicating arm, recorder pen or digital display board) including by way of illustration and not by way of limitation, the expansion or contraction of a Bourdon tube, pressure spiral or helix; the displacement of a bellows-flapper, nozzle-diaphram or differential transformer-core assembly; the movement of a bimetallic temperature responsive element; the motion of the slider of a self-balancing potentiometer.
  • the output signal may be transmitted without visual display directly to reset a final control element such as a diaphram motor valve or a sub-control loop in a cascade system.
  • the readout device will comprise or be coupled to an indicating or recorder means, the scale or chart of which may further be calibrated in terms of the desired identifying characteristic of the hydrocarbon containing sample, such as octane number, initial boiling point, point, vapor pressure and the like,
  • Samples which can be analyzed by our invention include both normally gaseous and normally. liquid hydrocarbon-containing mixtures comprising either at least one hydrocarbon containing from 1 to about 22 carbon .atoms per molecule in admixture with one or more non-hydrocarbons such as H N C0, C0 H 0, and H 8, or at least two different hydrocarbons containing from 1 to about 22 carbon atoms per molecule.
  • the upper limit on carbon number is fixed by the operational requirement that the sample be vaporizable in the air stream under combustion conditions without undergoing any substantial thermal decomposition prior to the partial oxidization thereof.
  • the hydrocarbon or hydrocarbons may be 'normal paraflins, isoparafiins, monolefins, diolefins, or polyolefins, cycloparaflins, cycloolefins, mononuclear aromatics or polynuclear aromatics.
  • hydrocarbon compounds which may be present in the hydrocarbon-containing samples include methane, ethane, propane, n-butane, isobutane, pentanes, hexanes, octanes, heptanes, nonanes, decanes, undecanes, dodecanes tridecanes, tetradecanes, pentadecanes, hexadecanes, heptadecanes, octadecanes, nonadecanes, icosanes, ethylene, proplene, l-butene, 2-butene, isobutylene, pentenes, hexenes, butadienes, pentadienes, hexadienes, cyclobutane, cyclopentane, cyclohexane, cycloheptane, benzene, toluene, orthoxylene, metaxylene, paraxylene, pen
  • hydrocarbon-containing or hydrocarbonaceous streams encountered commercially which may be analyzed by our invention include natural gas, refinery olfgas; recycle hydrogen streams in catalytic reforming and catalytic hydrocracking units which typically contain significant amounts of C -C hydrocarbons in addition to hydrogen; pyrolysis gas; fluid catalytic cracking oflgas; poly feed; straight run gasoline; cracked gasoline; poly gasoline; motor alkylate; catalytically reformed gasoline; hydrocracker products; products of BTX fractionation detergent alkylate, heavy naphthas; kerosene; diesel oil; light cycle oil; heavy cycle oil; light vacuum gas oil; and heavy vacuum gas oil.
  • the oxidizing agent used by our apparatus is preferably an oxygencontaining gas such as air, substantially pure oxygen, or a synthetic blend of oxygen with an inert or equilibrium-affecting diluent such as N CO or steam.
  • an oxygencontaining gas such as air, substantially pure oxygen, or a synthetic blend of oxygen with an inert or equilibrium-affecting diluent such as N CO or steam.
  • the adjusted combustion parameter is hydrocarbon concentration, oxygen concentration or diluent concentration in the combined feed
  • control may be accomplished by varying the flow rate of hydrocarbon, oxygen or diluent as the case may be, or by simultaneously varying the flow rates of two of these streams in order to maintain a constant air: hydrocarbon ratio or constant hydrocarbon: diluent ratio.
  • the generation of the stabilized cool flame is effected under superatmospheric pressure and at elevated temperature.
  • pressure may be in the range of about 18 p.s.i.a. to about 165 p.s.i.a., with a maximum flame front temperature of the order of 600100O F.
  • pressures in the range of 20-65 p.s.i.a., more preferably in the range of 25-50 p.s.i.a., together with induction zone temperatures in the range of 550-850 F.
  • Control of induction zone temperature can be effected by the amount of preheat imparted to the incoming sample and air streams and also by supplying heat from an external source to the combustion chamber itself.
  • permissible limits within which pressure and temperature may be independently varied without departure from stable operation can be determined by simple experiment for a particular type of sample.
  • FIGURE 1 is a sectional elevation view of one form of analyzer.
  • FIGURE 2 is a schematic diagram of a flame position sensor-controller utilized with the FIGURE 1 apparatus.
  • FIGURE 3 is a typical temperature profile existing in the FIGURE 1 apparatus.
  • FIGURE 4 is a typical octane number-pressure correlation curve.
  • FIGURES 5, 6, and 7 are schematic flow diagrams of different embodiments of the invention wherein respectively different combustion parameters are varied to servoposition the flame front.
  • the apparatus comprises an outer casing or canister 10 having a closed lower end and an open upper end.
  • Canister 10 is provided with a fluid heating medium inlet conduit 11 and a heating medium outlet conduit 12.
  • the upper end of the canister is formed into a lip or flange 13.
  • a top cover plate 14, seated upon an annular gasket 15, is sealably secured to flange 13 by means of a number of circumferentially spaced throughbolts 16.
  • Plate 14 and canister 10 therefore define a fluid-tight, heat retentive chamber or coflin adapted to contain the combustion tube proper.
  • the exterior of canister 10 and plate 14 may be encased by one or more layers of insulation and/or adiabatic lagging.
  • Tube 17 Extending through and depending from plate 14 is an elongate thin-walled combustion tube 17.
  • the lower end of tube 17 is open while the upper end is closed by a cap 18.
  • Tube 17 is attached to and supported by plate 14 by a circular fillet weld 19.
  • a burner nozzle assembly indicated generally by numeral 20, is affixed to the lower end of tube 17.
  • Such nozzle assembly includes a threaded sleeve nozzle block 21 slipped over the lower end of tube 17.
  • Block 21 is provided with a lower axial orifice 22 opening into an orifice extension housing 23.
  • Air is charged to the aforesaid nozzle assembly through line 26, flow controller 27 and tubing 28.
  • Tubing 28 is run through a slightly larger opening 29 in top plate 14, and is sealed thereto by a threaded sleeve and collar compression fitting 30.
  • the tubing 28 is formed into a helically wound section 31 concentric about tube 17 to provide adequate .heat transfer area for the air preheating zone.
  • the lower end of tubing 28 is passed through the sidewall of housing 23.
  • Hydrocarbon sample is charged to the nozzle assembly through line 33, flow controller 34 and tubing 35.
  • Tubing 35 is run through a slightly larger opening 36 in top plate 14 and is sealed thereto by a threaded sleeve and collarcompression fitting 37.
  • the section of tubing 35 within canister 10 constitutes the hydrocarbon vaporizing and preheating zone.
  • the lower end of tubing 35 is passed through the endwall of orifice extension housing 23, then extended upwardly concentrically within housing 23 and orifice 22 and terminates in a tip or inner nozzle 32 flush with the upper end of orifice 22.
  • a flow diffuser element 38 is mounted across the interior of tube 17 a short distance above the burner nozzle.
  • This diffuser element may be constructed of stainless steel wool or glass wool, or it may instead be a porous sintered metal plate or a porous ceramic plate.
  • Vent gases comprising the partial oxidation products of the stabilized cool flame are removed from the combustion tube through line 39 which includes a back pressure regulator or controller 40. If desired, the vent gases may be passed through a thermal or catalytic oxidation zone, located upstream or downstream from pressure regulator 40, to effect the complete combustion thereof to carbon dioxide and water.
  • the front of the stabilized cool flame is a relatively narrow well-defined transverse section spaced a predetermined distance above the nozzle assembly.
  • the detection of the physical position of the flame is effected by temperature responsive thermoelectric means; other equivalent means will be described hereinbelow.
  • the flame position sensing means comprises a pair of axially spaced thermocouples 41 and 42 which are inserted into thin-walled pencil-type thermowells 43 and 44, respectively, such thermowells preferably having a low heat capacity coupled with a relatively high thermal conductivity in the longitudinal direction.
  • Thermocouples 41 and 42 may be iron-constantan couples, for example, and are connected in voltage opposition.
  • thermocouple lead wires 45 and 46 are brought out of the canister 10 through ceramic insulating disconnects 47 which extend through and are bonded to cover plate 14. Leadwires 45 and 46 are connected to the input terminals of a suitable differential temperature controller 48.
  • a suitable differential temperature controller 48 may be a conventional self-balancing potentiometer in combination with pneumatic control means.
  • a suitable input span for the controller 48 may be to +5 millivolts, and the output signal thereof, transmitted through line 49, may be a conventional 315 p.s.i. air signal. Such control signal is taken through line 49 to reset the setpoint of back pressure controller 40.
  • the readout means of this embodiment is a pressure recorder 50 connected via pressure tap 51 to line 35! upstream from controller 40.
  • FIGURE 3 is a typical temperature profile of a stabilized cool flame generator burning a gasoline fraction in a 1" tube under a pressure of 30-50 p.s.i.a. Tube length is measured from the burner nozzle.
  • Letters a and b designate the location of thermocouples 42 and 41, respectively.
  • the temperature of the induction Zone is about 630 F. In the region of the flame front, the temperature climbs rapidly, peaking at about 750 F., then falling off rapidly to about 640 F. When the flame front is exactly positioned between thermocouples 41 and 42, both couples will be at about the same temperature and the net voltage appearing at the input of differential temperature controller 48 will be approximately zero.
  • thermocouple 42 will reflect a temperature rise
  • thermocouple 41 will reflect a temperature drop
  • differential temperature controller 48 will act through controller 40 to decrease combustion pressure until the front is restored to its original position.
  • thermocouple 41 will reflect a temperature rise
  • thermocouple 42 will reflect a temperature drop
  • differential temperature controller 48 will act to increase combustion pressure until the front is restored to its original position.
  • the change in combustion pressure required to immobilize the flame front following a composition change is a correlatable function of such composition change.
  • the heating fluid introduced to canister 10 through line 11 may be air, flue gases, saturated or superheated steam, oil, alcohol, molten salt, or other suitable medium obtained from an external thermostaticaly regulated source thereof.
  • a circulating heating medium one may employ a confined liquid bath surrounding tube 17 which may be heated and thermostatically regulated by an electric immersion heater, steam coils, etc.
  • the temperature of the heating medium or constant temperature bath will, in general, be established in the range of about Combustion tube 29.5 long x 1" OD. x #20 BWG stainless steel tubing.
  • Air Preheater 20 turns A" OD. x #22 BWG tubing on 3" diameter at l" spacing.
  • the curve of FIGURE 4 is a typical octane numberpressure correlation for the above-described analyzer operating as specified, utilizing synthetic blends of n-heptaneisooctane as test samples. Combustion pressure, plotted along the ordinate, is read from pressure recorder 50. The curve is substantially linear above 94 octane, and shows a slight upward concavity for lower octane numbers. Since the analyzer output is a continuous analog signal, it will be appreciated that the analyzer can easily be incorporated into a conventional process control loop.
  • FIGURE 5 illustrates another embodiment of our invention in which the adjusted combustion parameter is hydrocarbon flow rate. Elements identical to those of FIGURE I bear the same numeral.
  • combustion pressure is held constant by regulator 40.
  • the control output of differential controller 48 is transmitted via line 49 to reset hydrocarbon flow controller 34.
  • the readout means is a flow recorder 60 coupled via line 61 to controller 34.
  • FIGURE 6 illustrates another embodiment of our invention in which the adjusted combustion parameter is air flow rate. Elements identical to those of FIGURE 1 bear the same numeral. Here also combustion pressure is held constant by regulator 40.
  • the control output of differential temperature controller 48 is transmitted via line 49 to reset air flow controller 27.
  • the readout means is a flow recorder 60 coupled via line 62 to controller 27.
  • FIGURE 7 illustrates another embodiment of our invention in which the adjusted combustion parameter is induction zone temperature. Elements identical to those of FIGURE I bear the same numeral. Combustion pressure is held constant by regulator 40. Induction zone temperature is controlled by a temperature recorder controller 70, the input to which is developed by a thermocouple 71 located in the induction zone within the combustion tube 17. The output from controller 70 is transmitted through line 73 to drive a diaphragm motor valve 72 serially connected into line 12. By so throttling the flow of the heat transfer medium through canister 10, which in turn alfects heat transfer coeflicients and mean temperature differences, the total heat input to the charge streams and to the combustion tube 17 can be varied, and this in turn affects induction zone temperature.
  • differential temperature controller 48 The control output of differential temperature controller 48 is transmitted via line 49 to reset the temperature recorder controller 70.
  • the readout means is simply the pen and chart of recorder-controller 70. With all other combustion parameters constant, an increase in flame induction zone temperature will cause the flame front to recede toward the nozzle, and a decrease in temperature will cause the front to advance away from the nozzle. Therefore, if the hydrocarbon composition changes in a manner such that the front tends to move back toward the nozzle, differential temperature controller 48 will act to decrease the flame induction zone temperature until the front is restored to its original position. Conversely, if the hydrocarbon composition changes in a manner such that the front attempts to move farther away from the nozzle, differential temperature controller 48 will act to increase the flame induction zone temperature until the front is again restored to its original position.
  • the rate of flow of heating medium may be fixed at a predetermined level and the output of temperature controller 70 may be utilized to vary the temperature of the flowing heating medium at the heating source therefor. Because of the heat capacities of the streams and materials of construction, the servo-positioning system of FIGURE 7 may be expected to be somewhat slower and less stable than the systems heretofore illustrated in FIG- URES 1, 5 and 6.
  • FIGURE 5 the correlation is between hydrocarbon flow and hydrocarbon composition.
  • FIGURE 6 the correlation is between air flow and hydrocarbon composition.
  • FIGURE 7 the correlation is between flame induction zone temperature and hydrocarbon composition.
  • thermoelectric elements Other means for detecting flame position will be apparent to those skilled in the control arts and are deemed embraced in the broad scope of our invention.
  • spaced resistance bulbs or simply a pair of spaced resistance wires stretched taut across the combustion tube, connected in a standard bridge circuit, instead of thermoelectric elements.
  • optical-electric means such as radiation pyrometers or photoelectric pyrometers.
  • the flame region may comprise a capacitor in the tank circuit of a high frequency oscillator whereby linear displacement of the flame will change the dielectric constant of the capacitor and hence the resonance characteristic of the oscillator; or the flame region may comprise a direct current ionization gap.
  • a hydrocarbon analyzer comprising:
  • a combustion chamber including an induction section thereof
  • control means coupled to said sensing means and to said generating means adapted to adjust a combustion parameter selected from the group consisting of combustion pressure, induction section temperature and oxidizer flow in a manner to maintain the physical position of said flame constant relative to the combustion chamber;
  • readout means developing a signal responsive to said combustion parameter which in turn provides a measure of fuel composition.
  • a hydrocarbon analyzer comprising:
  • means for generating a stabilized cool flame within said combustion chamber including burner means, a hydrocarbon inlet line connecting with said burner means, and means for varying the pressure in said combustion chamber;
  • control means coupled to said sensing means and to said pressure-varying means adapted to adjust combustion pressure in a manner to immobilize said flame with respect to said burner means regardless of changes in the composition of hydrocarbon charged through said hydrocarbon inlet line;
  • readout means connecting with said combustion chamber and developing a signal responsive to combustion pressure which in turn provides a measure of said hydrocarbon composition.
  • a hydrocarbon analyzer comprising:
  • means for generating a stabilized cool flame within said combustion tube including burner means disposed at one end thereof, and a hydrocarbon inlet line connecting with said burner means;
  • control means coupled to said sensing means and to said back pressure-varying means adapted to adjust combustion pressure in a manner to immobilize said flame with respect to said burner means regardless of changes in the composition of hydrocarbon charged through said hydrocarbon inlet line;
  • readout means connecting with said combustion tube and developing a signal responsive to combustion pressure which in turn provides a measure of said hydrocarbon composition.
  • said flame position sensing means comprises a pair of axially spaced temperature responsive elements.
  • a hydrocarbon analyzer comprising:
  • (1) means for generating a stabilized cool flame within said combustion chamber including burner means, a hydrocarbon inlet line and an oxidizer inlet line both connecting with said burner means, and means for varying the rate of flow of oxidizer charged through said oxidizer inlet line;
  • control means coupled to said sensing means and to said oxidizer flow-varying means adapted to adjust oxidizer flow in a manner to immobilize said flame with respect to said burner means regardless of changes in the composition of hydrocarbon charged through said hydrocarbon inlet line;
  • readout means connecting with said oxidizer inlet line and developing a signal responsive to oxidizer flow rate which in turn provides a measure of said hydrocarbon composition.
  • a hydrocarbon analyzer comprising:
  • a combustion chamber including an induction section thereof
  • means for generating a stabilized cool flame within said combustion chamber including burner means, a hydrocarbon inlet line connecting with said burner means, and means for varying the temperature of said induction section;
  • control means coupled to said sensing means and to said temperature-varying means adapted to adjust induction section temperature in a manner to immobilize said flame with respect to said burner means regardless of changes in the composition of hydrocarbon charged through said hydrocarbon inlet line;
  • readout means connecting with said induction section and developing a signal responsive to induction section temperature which in turn provides a measure of said hydrocarbon composition.
  • a hydrocarbon analyzer comprising:
  • a combustion tube including an induction section thereof
  • means for generating a stabilized cool flame within said combustion tube including burner means disposed at one end thereof, and a hydrocarbon inlet line and an oxidizer inlet line both connecting with said burner means;
  • combustion parameter adjusting means including means for adjusting combustion pressure, means for adjusting the rate of flow of oxidizer charged through said oxidizer inlet line, and means for adjusting the temperature of said induction section;
  • control means coupled to said sensing means and to a selected one of said combustion parameter adjusting means adapted to adjust such parameter in a manner to immobilize said flare with respect to said burner means regardless of changes in the composition of hydrocarbon charged through said hydrocarbon inlet line;
  • readout means developing a signal responsive to the parameter adjusted by said selected one of said combustion parameter adjusting means which in turn provides a measure of said hydrocarbon composition.
  • thermocouples 9. The apparatus of claim 8 further characterized in that said sensing means comprises a pair of axially spaced thermocouples.
  • composition of a hydrocarbon-containing mixture which comprises:
  • the method of claim 15 further characterized in that the temperature of the combustion zone upstream from said flame front is in the range of 550-850 F.
  • the method of claim 15 further characterized in 13 14 that the pressure of the combustion zone is in the range OTHER REFERENCES of 20455 Barusch, M. R. et al., Industrial and Engineering 18.
  • the method of claim 15 further characterized in that the pressure of the combustion zone is in the range Chemlstry 2329 32 (19511) Of 255 P- 5 MORRIS O. WOLK, Primary Examiner References Cited ELLIOTT A. KATZ, Assistant Examiner UNITED STATES PATENTS 2,603,085 7/1952 Cannon. US. Cl. X.R. 3,262,486 7/1966 R086. 21 232 2g 25'4. 4';1 75 3,295,585 1/1967 Kayach et a1, l

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Description

Aug.26,-1969 E. R. FENSKE ETAL 3,463,613
HYDROCARBON ANALYZER COMPRISING STABILIZED COOL FLAME GENERATOR WITH SERVO-POSITIONED FLAME FRONT Filed July 13. 1965 6 Sheets-Sheet 1 Figure] ,4'45 1%; 46\ 11 I I ,1 E} I F 46 I Healing '45 i Med/um In I [48 l AT 00nfro//er-\ "Combusf/on Tube y Pressure Recorder Van! Gas N V EN 70/78 E //s wort/7 R. Fens/re BY James H. McLaugh/m A rromvzrs Aug. 26, 1969 E. R. FENSK-E- ETAL. 3,463,613
HYDROCARBON ANALYZER COMPRISING STABILIZED COOL FLAME GENERATOR WITH SERVO-POSITIONED FLAME FRONT 6 Sheets-Sheet 2 Filed July 13, 1965 Figure 3.
w 5. D 2 p I ufl l l -IBLtIVIIIIII I. ll4||-| lllllo A 2 a m F l m M F m 5 0 0 0 0 0 0 0 0 w M m 6 6 w KQ EMQE m sutmamfiob /m K0 2 w mw e r n n d u. m 3 g m m I l I F 4 m M 6 Tuba Lang/h, Inches.
Figure 4 Oclane Na, F-l Clear IN vE/v TORSI m 5 a? 5 @M Zw m M W5 M MW Aug. 26, 1969 E. R. FENSKE ETAL 1 3,463,513
HYDROCARBON ANALYZER COMPRISING STABILIZED COOL FLAME GENERATOR WITH SERVO-POSITIONED FLAME FRONT Filed Jfily 13, 1965 5 Sheets-Shae 3 Figure 5 Figure 6 A TCon/rol/er n v A T Con/roller F0 F6 I 26 33 I 26 AI! fez AI! Hydrocarbon Hydrocarbon so /60 6) -Flow Recorder F gure 7 49 Healing Med/um Temperature In Re cordar- Con/roller r 1 46 1a.: I 70 n 7 i 1 AT Control/er 73-\ E k I I I2 7 f i LJ 1 Healing Medi mus/v ms.- E I/swarlh R. Fanske James H. McLaughlin Hydrocarbon W @Mm United States Patent Int. Cl. Gllln 33/22 US. Cl. 23-230 18 Claims ABSTRACT OF THE DISCLOSURE The composition of a hydrocarbon containing sample mixturesuch as a gasoline fraction-is determined by burning said mixture in a combustion tube under conditions to generate therein a stabilized cool flame. The position of the flame front is automatically detected and used to develop a control signal which, in turn, is used to vary a combustion parameter, such as pressure, temperature or air flow, in a manner to immobilize the flame front regardless of changes in composition of the sample mixture. The change in such combustion parameter required to immobilize the flame following a change of sample composition is correlatable with such composition change. A suitable readout device may be calibrated in terms of the desired identifying characteristic of the hydrocarbon-containing sample, as, for example, octane number.
This invention relates to the determination of the composition of hydrocarbon-containing mixtures or hydrocarbon fractions and more particularly to methods and apparatus for analyzing hydrocarbon mixtures which utilize a stabilized cool flame generator. Our apparatus is useful not only in the laboratory but more especially as a continuous process stream analyzer adapted for on-site use in a petroleum refinery or chemical plant in performing indicating, recording and/or process control functions.
The phenomena of cool flames has been the subject of previous investigations and technical publications. When a mixture of hydrocarbon vapor and oxygen or air within the explosion limits is held at conditions of pressure and temperature below the normal ignition point, partial oxidation reactions occur which result in the formation of aldehydes, carbon monoxide and other partially oxidized combustion products such as ketones and acids. It is believed that these are the products of a chain reaction which also produce ions which then continue the reaction chain by attacking other hydrocarbon molecules. At some conditions, the formation of more highly branched chain molecules is favored, while at other conditions, perhaps at higher or lower temperatures, the formation of branched chain products is diminished by competing reactions which use up ions. If such a mixture is contained and compressed and/or heated so that these chain reactions proceed at significant rates, so-called cool flame are observed after an induction period. These cool flames are light emissions accompanied by the evolution of mild amounts of heat less than the heat of combustion. Depending on the conditions, cool flames may quench or after a second induction period, the mixture may ignite spontaneously and explode; this latterphenomenon is known as autoignition. It is also possible to so regulate the combustion parameters that a continuous or stabilized cool flame results e.g., a flame which neither quenches nor develops into the autoignition phase but rather manifests itself as a stable, well-defined flame front. Baruseh and Payne, In-
dustrial Engineering Chemistry, 432,329 (1951), describe the results of work in which they developed a continuous or stabilized flame. Their apparatus included a flow tube with a nozzle assembly at one end thereof for injection of hydrocarbon and air and was designed to operate at atmospheric pressure. The distance from the end of their flow tube to the front of the cool flame was, at otherwise constant conditions, a measure of induction time which increased with the F-1 octane number of n-heptaneisooctane blends, and at least agreed with the octane number of other pure compounds and some mixtures.
The generation and maintenance of a continuous or stabilized cool flame is dependent on a number of operating parameters as well as the dimensions of the specific apparatus utilized therefor. These include the following:
A. Uncontrolled and potentially variable parameter:
Hydrocarbon composition.
B. Designable but otherwise fixed parameters:
(1) Configuration of combustion tube, such as shape of cross-section, cross-sectional area, length, degree of taper if any, etc.
(2) Burner nozzle design, such as cross-sectional areas of hydrocarbon and oxidizer inlets, volume and shape of mixing chamber, etc.
C. Adjustable and/or regulatable combustion parameters:
(1) Combustion pressure.
(2) Concentration of hydrocarbon in combined feed.
(3) Concentration of oxygen in combined feed.
(4) Concentration of inert or equilibrium-affecting diluent in combined feed, if any such as N steam or C0 (5) Induction zone temperature.
We have discovered that when the cool flame is generated under superatmospheric pressure and a hydrocarbon-containing mixture or hydrocarbon fraction of time varying composition is charged to the combustion zone, it is possible to readjust one or more of the combustion parameters enumerated under part C above in such a manner that the physical position of the flame is maintained constant with respect to the combustion tube, or, in other words, the flame front is immobilized or rendered substantially stationary relative to the burner nozzle. That is to say, whereas the prior art maintained all combustion parameters constant for a given run and thereby observed a displacement of the flame front upon the change of hydrocarbon composition, indeed in many cases the flame becoming unstable and degenerating into flame-out or propagating into explosion, we have found it possible and practical to control the combustion process whereby the cool flame is not only stabilized but is also immobilized. More significantly, we have further discovered that when the position of the stabilized cool flame is so controlled by varying a combustion parameter, the change in such combustion parameter necessary to immobilize the flame following a change of hydrocarbon composition is corre: latable with, or otherwise responsive to, such hydrocarbon composition change.
Our invention therefor relates to methods and apparatus for analyzing hydrocarbon containing mixtures based on the generation of a stabilized cool flame. The present invention distinguishes over the prior art in at least four important respects: (1) the partial combustion is effected under superatmospheric pressure: (2) the provision of means to sense the physical position of the flame; (3) the use of such flame-positio information to reset a combustion parameter such that the flame front is immobilized; and (4) the provision of means to indicate, display or otherwise read out such combustion parameter which, as indicated above, is correlata'ble with the hydrocarbon composition.
In one aspect our invention embodies a hydrocarbon analyzer comprising a combustion chamber; means for generating a stabilized cool flame Within the combustion chamber utilizing as fuel therefor a hydrocarbon-containing mixture to be analyzed; means for sensing the physical position of said flame within the combustion chamber; control means coupled to said sensing means and to said generating means adapted to adjust a combustion parameter in a manner to maintain the physical position of the flame constant relative to the combustion chamber; and readout means developing a signal responsive to said combustion parameter which in turn provides a measure of hydrocarbon composition.
In a more specific embodiment this invention is directed to a hydrocarbon analyzer comprising a combustion chamber; means for generating a stabilized cool flame within the combustion chamber including burner means, a hydrocarbon inlet line connecting with the burner means, and means for varying the preseure within said combustion chamber; means for sensing the physical position of the stabilized cool flame within the combustion chamber, said sensing means being spaced a predetermined distance from the burner means; feedback control means coupled to said sensing means and to said pressure-varying means adapted to adjust combustion pressure in a manner to immobilize said flame with respect to the burner means, regardless of the changes in the composition of the hydrocarbon charged through the hydrocarbon inlet line; and readout means connecting with the combustion chamber and developing a signal responsive to the combustion pressure which in turn provides a measure of hydrocarbon composition.
In another aspect our invention relates to a method of detecting changes in composition of a hydrocarbon containing mixture which comprises introducing a sample stream of said mixture and a stream of oxygen-containing gas into one end of a combustion zone maintained at elevated temperature and under superatmospheric pressure; therein partially oxidizing the hydrocarbon constituents of said sample under conditions to generate in said zone a stabilized cool flame characterized by a relatively narrow, well-defined flame front spaced from said one end; sensing the position of said front relative to said one end and developing therefrom a control signal; utilizing said control signal to adjust a combustion parameter such as combustion pressure, sample flow rate, oxygen-containing gas flow rate, or induction zone temperature in a manner to immobilize said flame front relative to said one end regardless of changes in hydrocarbon composition; and sensing said adjusted parameter and developing therefrom an output signal responsive to changes in sample composition.
A further embodiment of this invention embraces a method for detecting changes in composition of a normally liquid hydrocarbon fraction which comprises introducing a preheated vaporized stream of said hydrocarbon fraction and a preheated stream of air into one end of a combustion zone maintained at elevated temperature and under superatmospheric pressure; therein partially oxidizing said hydrocarbon fraction under conditions to generate in said zone a stabilized cool flame characterized by a relatively narrow, well-defined flame front spaced from said one end; sensing the position of the flame front relative to said one end and developing therefrom a control signal; varying the pressure of said combustion zone responsive to said control signal in a manner to immobilize said flame front relative to said one end regardless of changes in hydrocarbon composition; and sensing said combustion pressure and developing therefrom an output signal responsive to changes in said hydrocarbon composition.
As used herein the terms hydrocarbon analyzer or hydrocarbon analysis do not mean a compound-by-compound analysis of the type presented by instruments such as mass spectrometers or vapor phase chromatographs; rather the analysis is represented by a continuous, or substantially continuous, output signal which is responsive to and indicative of hydrocarbon composition and, more specifically, is empirically correlatable With one or more conventional identifications or specifications of petroleum products such as Reid vapor pressure, ASTM or Engler distillations, and, for motor fuels, knock characteristics such as research octane number, motor octane number, and the like. The specific nature of the correlation is a function of composition and carbon number and is further influenced by the presence or absence of paraflins, isoparafiins, olefins, diolefins and polyolefins, aromatics, long chain substituted aromatics, polynuclear aromatics, etc. Thus, it is contemplated that the present analyzer will be calibrated for a particular hydrocarbon blend or charge stock and relatively small composition deviations therefrom can be accounted for by linear extrapolation; for example, a different calibration may be found necessary when the hydrocarbon sample is changed from catalytically reformed gasoline to catalytically cracked gasoline. Such characteristic in no way detracts from the usefulness of our invention, and is inconsequential where the apparatus is employed as an on-stream analyzer for the measurement and/or control of a particular refinery process stream since potential composition deviations will be relatively minor in such application. In any event, our invention affords a rapid and simple means for detecting composition changes, and for supplying information as to the required direction and magnitude of corrective action to be applied to a controlled processing condition in order to restore the sample composition to specifications.
The term output signa or signal developed by the readout means is to be construed in its broadest meaningful sense and includes analog signals of all types such as amplitude-modulated, phase-modulated, or frequencymodulated electrical signals or pressure signals by conventional pneumatic transmission media, as well as digital representations of the foregoing. The output signal is further intended to include simple mechanical motion or displacement of a transducer member (whether or not mechanically, electrically or pneumatically coupled to a visual display means such as an indicating arm, recorder pen or digital display board) including by way of illustration and not by way of limitation, the expansion or contraction of a Bourdon tube, pressure spiral or helix; the displacement of a bellows-flapper, nozzle-diaphram or differential transformer-core assembly; the movement of a bimetallic temperature responsive element; the motion of the slider of a self-balancing potentiometer. The output signal may be transmitted without visual display directly to reset a final control element such as a diaphram motor valve or a sub-control loop in a cascade system. Preferably, however, the readout device will comprise or be coupled to an indicating or recorder means, the scale or chart of which may further be calibrated in terms of the desired identifying characteristic of the hydrocarbon containing sample, such as octane number, initial boiling point, point, vapor pressure and the like,
Samples which can be analyzed by our invention include both normally gaseous and normally. liquid hydrocarbon-containing mixtures comprising either at least one hydrocarbon containing from 1 to about 22 carbon .atoms per molecule in admixture with one or more non-hydrocarbons such as H N C0, C0 H 0, and H 8, or at least two different hydrocarbons containing from 1 to about 22 carbon atoms per molecule. The upper limit on carbon number is fixed by the operational requirement that the sample be vaporizable in the air stream under combustion conditions without undergoing any substantial thermal decomposition prior to the partial oxidization thereof. The hydrocarbon or hydrocarbons may be 'normal paraflins, isoparafiins, monolefins, diolefins, or polyolefins, cycloparaflins, cycloolefins, mononuclear aromatics or polynuclear aromatics. Specific examples of hydrocarbon compounds which may be present in the hydrocarbon-containing samples include methane, ethane, propane, n-butane, isobutane, pentanes, hexanes, octanes, heptanes, nonanes, decanes, undecanes, dodecanes tridecanes, tetradecanes, pentadecanes, hexadecanes, heptadecanes, octadecanes, nonadecanes, icosanes, ethylene, proplene, l-butene, 2-butene, isobutylene, pentenes, hexenes, butadienes, pentadienes, hexadienes, cyclobutane, cyclopentane, cyclohexane, cycloheptane, benzene, toluene, orthoxylene, metaxylene, paraxylene, ethylbenzene, n-propylbenzene, cumene, acetylene, tetramethylbenzenes, pentamethylbenzenes, hexamethylbenzenes, naphthlene, anthracene, and phenanthrene. Specific examples of hydrocarbon-containing or hydrocarbonaceous streams encountered commercially which may be analyzed by our invention include natural gas, refinery olfgas; recycle hydrogen streams in catalytic reforming and catalytic hydrocracking units which typically contain significant amounts of C -C hydrocarbons in addition to hydrogen; pyrolysis gas; fluid catalytic cracking oflgas; poly feed; straight run gasoline; cracked gasoline; poly gasoline; motor alkylate; catalytically reformed gasoline; hydrocracker products; products of BTX fractionation detergent alkylate, heavy naphthas; kerosene; diesel oil; light cycle oil; heavy cycle oil; light vacuum gas oil; and heavy vacuum gas oil.
The oxidizing agent used by our apparatus is preferably an oxygencontaining gas such as air, substantially pure oxygen, or a synthetic blend of oxygen with an inert or equilibrium-affecting diluent such as N CO or steam. Where the adjusted combustion parameter is hydrocarbon concentration, oxygen concentration or diluent concentration in the combined feed, such control may be accomplished by varying the flow rate of hydrocarbon, oxygen or diluent as the case may be, or by simultaneously varying the flow rates of two of these streams in order to maintain a constant air: hydrocarbon ratio or constant hydrocarbon: diluent ratio.
As earlier indicated, the generation of the stabilized cool flame is effected under superatmospheric pressure and at elevated temperature. In general, such pressure may be in the range of about 18 p.s.i.a. to about 165 p.s.i.a., with a maximum flame front temperature of the order of 600100O F. For measuring composition of a gasoline boiling range hydrocarbon fraction, we prefer to employ pressures in the range of 20-65 p.s.i.a., more preferably in the range of 25-50 p.s.i.a., together with induction zone temperatures in the range of 550-850 F. Control of induction zone temperature can be effected by the amount of preheat imparted to the incoming sample and air streams and also by supplying heat from an external source to the combustion chamber itself. In any case the permissible limits Within which pressure and temperature may be independently varied without departure from stable operation can be determined by simple experiment for a particular type of sample.
The structure and mode of operation of our invention, including the several embodiments thereof, are more completely described with reference to the accompanying drawings in which:
FIGURE 1 is a sectional elevation view of one form of analyzer.
FIGURE 2 is a schematic diagram of a flame position sensor-controller utilized with the FIGURE 1 apparatus.
FIGURE 3 is a typical temperature profile existing in the FIGURE 1 apparatus.
FIGURE 4 is a typical octane number-pressure correlation curve.
FIGURES 5, 6, and 7 are schematic flow diagrams of different embodiments of the invention wherein respectively different combustion parameters are varied to servoposition the flame front.
In FIGURE 1, the apparatus comprises an outer casing or canister 10 having a closed lower end and an open upper end. Canister 10 is provided with a fluid heating medium inlet conduit 11 and a heating medium outlet conduit 12. The upper end of the canister is formed into a lip or flange 13. A top cover plate 14, seated upon an annular gasket 15, is sealably secured to flange 13 by means of a number of circumferentially spaced throughbolts 16. Plate 14 and canister 10 therefore define a fluid-tight, heat retentive chamber or coflin adapted to contain the combustion tube proper. If desired, the exterior of canister 10 and plate 14 may be encased by one or more layers of insulation and/or adiabatic lagging.
Extending through and depending from plate 14 is an elongate thin-walled combustion tube 17. The lower end of tube 17 is open while the upper end is closed by a cap 18. Tube 17 is attached to and supported by plate 14 by a circular fillet weld 19. A burner nozzle assembly, indicated generally by numeral 20, is affixed to the lower end of tube 17. Such nozzle assembly includes a threaded sleeve nozzle block 21 slipped over the lower end of tube 17. A mating threaded collar 24, acting through a metallic gasket 25, engages the threaded sleeve of block 21 and draws the latter into compressive fluid-tight engagement with the wall of tube 17. Block 21 is provided with a lower axial orifice 22 opening into an orifice extension housing 23.
Air is charged to the aforesaid nozzle assembly through line 26, flow controller 27 and tubing 28. Tubing 28 is run through a slightly larger opening 29 in top plate 14, and is sealed thereto by a threaded sleeve and collar compression fitting 30. Within the canister 10 the tubing 28 is formed into a helically wound section 31 concentric about tube 17 to provide adequate .heat transfer area for the air preheating zone. The lower end of tubing 28 is passed through the sidewall of housing 23. Hydrocarbon sample is charged to the nozzle assembly through line 33, flow controller 34 and tubing 35. Tubing 35 is run through a slightly larger opening 36 in top plate 14 and is sealed thereto by a threaded sleeve and collarcompression fitting 37. The section of tubing 35 within canister 10 constitutes the hydrocarbon vaporizing and preheating zone. The lower end of tubing 35 is passed through the endwall of orifice extension housing 23, then extended upwardly concentrically within housing 23 and orifice 22 and terminates in a tip or inner nozzle 32 flush with the upper end of orifice 22.
A flow diffuser element 38 is mounted across the interior of tube 17 a short distance above the burner nozzle. This diffuser element may be constructed of stainless steel wool or glass wool, or it may instead be a porous sintered metal plate or a porous ceramic plate. Vent gases comprising the partial oxidation products of the stabilized cool flame are removed from the combustion tube through line 39 which includes a back pressure regulator or controller 40. If desired, the vent gases may be passed through a thermal or catalytic oxidation zone, located upstream or downstream from pressure regulator 40, to effect the complete combustion thereof to carbon dioxide and water.
The front of the stabilized cool flame is a relatively narrow well-defined transverse section spaced a predetermined distance above the nozzle assembly. In the present embodiment, the detection of the physical position of the flame is effected by temperature responsive thermoelectric means; other equivalent means will be described hereinbelow. With reference to FIGURES 1 and 2, the flame position sensing means comprises a pair of axially spaced thermocouples 41 and 42 which are inserted into thin-walled pencil-type thermowells 43 and 44, respectively, such thermowells preferably having a low heat capacity coupled with a relatively high thermal conductivity in the longitudinal direction. Thermocouples 41 and 42 may be iron-constantan couples, for example, and are connected in voltage opposition. The tips of the couples may be axially spaced a distance d ranging from about A to about 1%"; a greater spacing should generally be avoided since excessive loss of detection sensitivity may result. The thermocouple lead wires 45 and 46 are brought out of the canister 10 through ceramic insulating disconnects 47 which extend through and are bonded to cover plate 14. Leadwires 45 and 46 are connected to the input terminals of a suitable differential temperature controller 48. Such controller may be a conventional self-balancing potentiometer in combination with pneumatic control means. A suitable input span for the controller 48 may be to +5 millivolts, and the output signal thereof, transmitted through line 49, may be a conventional 315 p.s.i. air signal. Such control signal is taken through line 49 to reset the setpoint of back pressure controller 40. The readout means of this embodiment is a pressure recorder 50 connected via pressure tap 51 to line 35! upstream from controller 40.
FIGURE 3 is a typical temperature profile of a stabilized cool flame generator burning a gasoline fraction in a 1" tube under a pressure of 30-50 p.s.i.a. Tube length is measured from the burner nozzle. Letters a and b designate the location of thermocouples 42 and 41, respectively. The temperature of the induction Zone is about 630 F. In the region of the flame front, the temperature climbs rapidly, peaking at about 750 F., then falling off rapidly to about 640 F. When the flame front is exactly positioned between thermocouples 41 and 42, both couples will be at about the same temperature and the net voltage appearing at the input of differential temperature controller 48 will be approximately zero. However, we prefer to operate the apparatus with a small net voltage difference, either positive or negative, corresponding to a temperature differential of the order of -40 F. This means that the flame front is then slightly asymmetrical with respect to couples 41 and 42. While this mode achieves greater sensitivity, it is not a critical requirement and one may still realize good results if he chooses to control at zero differential. With all other combustion parameters constant, an increase in pressure will cause the flame front to recede toward the nozzle, and a decrease in pressure will cause the front to advance away from the nozzle. Therefore, if the hydrocarbon composition changes in a manner such that the front attempts to move back toward the nozzle, thermocouple 42 will reflect a temperature rise, thermocouple 41 will reflect a temperature drop and differential temperature controller 48 will act through controller 40 to decrease combustion pressure until the front is restored to its original position. Conversely, if the hydrocarbon composition changes in a manner such that the front attempts to move away from the nozzle, thermocouple 41 will reflect a temperature rise, thermocouple 42 will reflect a temperature drop and differential temperature controller 48 will act to increase combustion pressure until the front is restored to its original position. In any event, the change in combustion pressure required to immobilize the flame front following a composition change is a correlatable function of such composition change.
With regard to the operation of the analyzer, we prefer to install and use the combustion tube in a vertical position, as indicated in FIGURE 1, such that the flame front itself is substantially horizontal. If the flame is generated in a horizontal tube, the discular flame front tends to lay over, becoming slightly inclined to the vertical under the influence of gravity, which in turn reduces the sensitivity of the flame position sensing means. The heating fluid introduced to canister 10 through line 11 may be air, flue gases, saturated or superheated steam, oil, alcohol, molten salt, or other suitable medium obtained from an external thermostaticaly regulated source thereof. Alternatively, instead of a circulating heating medium, one may employ a confined liquid bath surrounding tube 17 which may be heated and thermostatically regulated by an electric immersion heater, steam coils, etc. The temperature of the heating medium or constant temperature bath will, in general, be established in the range of about Combustion tube 29.5 long x 1" OD. x #20 BWG stainless steel tubing. Burner Assembly:
Air orifice (22) #48 drill. Orifice extension housing (23) l x ID tubing. Hydrocarbon injector tip (32) #18 hypodermic tubing.
Air Preheater 20 turns A" OD. x #22 BWG tubing on 3" diameter at l" spacing.
24 liquid cc./hr.
Thermocouple spacing d Hydrocarbon flow Air flow 3500 cc./min. (STP). Constant temperature bath 650 F. Flame temperature rise F. Flame position from inlet 21.5" Combustion pressure 25-50 p.s.i.a.
The curve of FIGURE 4 is a typical octane numberpressure correlation for the above-described analyzer operating as specified, utilizing synthetic blends of n-heptaneisooctane as test samples. Combustion pressure, plotted along the ordinate, is read from pressure recorder 50. The curve is substantially linear above 94 octane, and shows a slight upward concavity for lower octane numbers. Since the analyzer output is a continuous analog signal, it will be appreciated that the analyzer can easily be incorporated into a conventional process control loop.
FIGURE 5 illustrates another embodiment of our invention in which the adjusted combustion parameter is hydrocarbon flow rate. Elements identical to those of FIGURE I bear the same numeral. In this case combustion pressure is held constant by regulator 40. The control output of differential controller 48 is transmitted via line 49 to reset hydrocarbon flow controller 34. The readout means is a flow recorder 60 coupled via line 61 to controller 34. With all other combustion parameters constant, an increase in hydrocarbon flow will cause the flame front to advance away from the nozzle, and a decrease in hydrocarbon flow will cause the flame front to recede toward the nozzle. Therefore, if the hydrocarbon composition changes in a manner such that the front attempts to move back toward the nozzle, controller 48 will act to increase the hydrocarbon flow until the front is restored to its original position. Conversely, if the hydrocarbon composition changes in manner such that the front attempts to move farther away from the nozzle, controller 48 will act to decrease the hydrocarbon flow until the front is restored to its original position.
FIGURE 6 illustrates another embodiment of our invention in which the adjusted combustion parameter is air flow rate. Elements identical to those of FIGURE 1 bear the same numeral. Here also combustion pressure is held constant by regulator 40. The control output of differential temperature controller 48 is transmitted via line 49 to reset air flow controller 27. The readout means is a flow recorder 60 coupled via line 62 to controller 27. With all other combustion parameters constant, an increase in air flow will cause the flame front to advance away from the nozzle. Therefore, if the hydrocarbon composition changes in a manner such that the front attempts to move back toward the nozzle, controller 48 will act to increase the air flow until the front is restored to its original position. Conversely, if the hydrocarbon conversion changes in a manner such that the front attempts to move farther away from the nozzle, controller 48 will act to decrease the air flow until the front is again restored to its original position.
FIGURE 7 illustrates another embodiment of our invention in which the adjusted combustion parameter is induction zone temperature. Elements identical to those of FIGURE I bear the same numeral. Combustion pressure is held constant by regulator 40. Induction zone temperature is controlled by a temperature recorder controller 70, the input to which is developed by a thermocouple 71 located in the induction zone within the combustion tube 17. The output from controller 70 is transmitted through line 73 to drive a diaphragm motor valve 72 serially connected into line 12. By so throttling the flow of the heat transfer medium through canister 10, which in turn alfects heat transfer coeflicients and mean temperature differences, the total heat input to the charge streams and to the combustion tube 17 can be varied, and this in turn affects induction zone temperature. The control output of differential temperature controller 48 is transmitted via line 49 to reset the temperature recorder controller 70. The readout means is simply the pen and chart of recorder-controller 70. With all other combustion parameters constant, an increase in flame induction zone temperature will cause the flame front to recede toward the nozzle, and a decrease in temperature will cause the front to advance away from the nozzle. Therefore, if the hydrocarbon composition changes in a manner such that the front tends to move back toward the nozzle, differential temperature controller 48 will act to decrease the flame induction zone temperature until the front is restored to its original position. Conversely, if the hydrocarbon composition changes in a manner such that the front attempts to move farther away from the nozzle, differential temperature controller 48 will act to increase the flame induction zone temperature until the front is again restored to its original position. Alternatively, the rate of flow of heating medium may be fixed at a predetermined level and the output of temperature controller 70 may be utilized to vary the temperature of the flowing heating medium at the heating source therefor. Because of the heat capacities of the streams and materials of construction, the servo-positioning system of FIGURE 7 may be expected to be somewhat slower and less stable than the systems heretofore illustrated in FIG- URES 1, 5 and 6.
The responses of the embodiments of FIGURES 5, 6 and 7 are similar to that of FIGURE 1 in that, in each case, a continuous analog output signal is provided which reproducibly tracks changes in hydrocarbon composition. In FIGURE 5, the correlation is between hydrocarbon flow and hydrocarbon composition. In FIGURE 6, the correlation is between air flow and hydrocarbon composition. In FIGURE 7, the correlation is between flame induction zone temperature and hydrocarbon composition.
Other means for detecting flame position will be apparent to those skilled in the control arts and are deemed embraced in the broad scope of our invention. For example, one may employ spaced resistance bulbs, or simply a pair of spaced resistance wires stretched taut across the combustion tube, connected in a standard bridge circuit, instead of thermoelectric elements. Alternatively, one may employ optical-electric means such as radiation pyrometers or photoelectric pyrometers. Since the flame front contains an appreciable concentration of organic radicals and ions, its position may be detected by ion sensitive means; for example, the flame region may comprise a capacitor in the tank circuit of a high frequency oscillator whereby linear displacement of the flame will change the dielectric constant of the capacitor and hence the resonance characteristic of the oscillator; or the flame region may comprise a direct current ionization gap.
We claim as our invention:
1. A hydrocarbon analyzer comprising:
(1) a combustion chamber including an induction section thereof;
(2) means for generating a stabilized. cool flame within said combustion chamber utilizing as fuel therefor a hydrocarbon-containing mixture to be analyzed and including means to introduce an oxidizer to said chamber;
(3) means for sensing the physical position of said flame within the combustion chamber;
(4) control means coupled to said sensing means and to said generating means adapted to adjust a combustion parameter selected from the group consisting of combustion pressure, induction section temperature and oxidizer flow in a manner to maintain the physical position of said flame constant relative to the combustion chamber; and
(5) readout means developing a signal responsive to said combustion parameter which in turn provides a measure of fuel composition.
2. A hydrocarbon analyzer comprising:
(1) a combustion chamber;
(2) means for generating a stabilized cool flame within said combustion chamber including burner means, a hydrocarbon inlet line connecting with said burner means, and means for varying the pressure in said combustion chamber;
(3) means for sensing the physical position of said flame within the combustion chamber spaced a predetermined distance from the said burner means;
(4) control means coupled to said sensing means and to said pressure-varying means adapted to adjust combustion pressure in a manner to immobilize said flame with respect to said burner means regardless of changes in the composition of hydrocarbon charged through said hydrocarbon inlet line; and
(5) readout means connecting with said combustion chamber and developing a signal responsive to combustion pressure which in turn provides a measure of said hydrocarbon composition.
3. A hydrocarbon analyzer comprising:
(1) a combustion tube;
(2) means for generating a stabilized cool flame within said combustion tube including burner means disposed at one end thereof, and a hydrocarbon inlet line connecting with said burner means;
(3) a vent gas outlet means connecting with said combustion tube at a point axially spaced from said burner means, said outlet means including back pressure-varying means;
(4) means for sensing the physical position of said flame within the combustion tube disposed between said burner means and said outlet means;
(5) control means coupled to said sensing means and to said back pressure-varying means adapted to adjust combustion pressure in a manner to immobilize said flame with respect to said burner means regardless of changes in the composition of hydrocarbon charged through said hydrocarbon inlet line; and
(6) readout means connecting with said combustion tube and developing a signal responsive to combustion pressure which in turn provides a measure of said hydrocarbon composition.
4. The apparatus of claim 3 further characterized in that said back pressure-varying means comprises a back pressure controller.
5. The apparatus of claim 3 further characterized in that said flame position sensing means comprises a pair of axially spaced temperature responsive elements.
6. A hydrocarbon analyzer comprising:
(1) a combustion chamber;
(2) means for generating a stabilized cool flame within said combustion chamber including burner means, a hydrocarbon inlet line and an oxidizer inlet line both connecting with said burner means, and means for varying the rate of flow of oxidizer charged through said oxidizer inlet line;
(3) means, spaced a predetermined distance from said burner means for sensing the physical position of said flame within the combustion chamber;
(4) control means coupled to said sensing means and to said oxidizer flow-varying means adapted to adjust oxidizer flow in a manner to immobilize said flame with respect to said burner means regardless of changes in the composition of hydrocarbon charged through said hydrocarbon inlet line; and
() readout means connecting with said oxidizer inlet line and developing a signal responsive to oxidizer flow rate which in turn provides a measure of said hydrocarbon composition.
7. A hydrocarbon analyzer comprising:
(1) a combustion chamber including an induction section thereof;
(2) means for generating a stabilized cool flame within said combustion chamber including burner means, a hydrocarbon inlet line connecting with said burner means, and means for varying the temperature of said induction section;
(3) means, spaced a predetermined distance from said burner means, for sensing the physical position of said flame Within the combustion chamber;
(4) control means coupled to said sensing means and to said temperature-varying means adapted to adjust induction section temperature in a manner to immobilize said flame with respect to said burner means regardless of changes in the composition of hydrocarbon charged through said hydrocarbon inlet line; and
(5) readout means connecting with said induction section and developing a signal responsive to induction section temperature which in turn provides a measure of said hydrocarbon composition.
8. A hydrocarbon analyzer comprising:
(1) a combustion tube including an induction section thereof;
(2) means for generating a stabilized cool flame within said combustion tube including burner means disposed at one end thereof, and a hydrocarbon inlet line and an oxidizer inlet line both connecting with said burner means;
(3) combustion parameter adjusting means including means for adjusting combustion pressure, means for adjusting the rate of flow of oxidizer charged through said oxidizer inlet line, and means for adjusting the temperature of said induction section;
(4) means for sensing the physical position of said flame within the combustion tube axially spaced from the burner means;
(5) control means coupled to said sensing means and to a selected one of said combustion parameter adjusting means adapted to adjust such parameter in a manner to immobilize said flare with respect to said burner means regardless of changes in the composition of hydrocarbon charged through said hydrocarbon inlet line; and
(6) readout means developing a signal responsive to the parameter adjusted by said selected one of said combustion parameter adjusting means which in turn provides a measure of said hydrocarbon composition.
9. The apparatus of claim 8 further characterized in that said sensing means comprises a pair of axially spaced thermocouples.
10. The method of detecting changes in composition of a hydrocarbon-containing mixture which comprises:
(1) introducing a sample stream of said mixture and a stream of oxygen-containing gas into one end of a combustion zone including an induction zone maintained at elevated temperature and under superatmospheric pressure;
(2) therein partially oxidizing the hydrocarbon constituents of said sample under conditions to generate in said combustion zone a stabilized cool flame characterized by a relatively narrow, well-defined flame front spaced from said one end;
(3) sensing the position of said flame front relative to said one end and developing therefrom a control signal;
(4) utilizing said control signal to adjust a combustion parameter selected from the group consisting of combustion pressure, oxygen-containing and induction zone temperature in a manner to immobilize said flame front relative to said one end regardless of changes in sample composition; and
(5) sensing said adjusted parameter and developing therefrom an output singal responsive to changes in said sample composition.
11. The method of claim 10 wherein said adjusted combustion parameter is combustion pressure.
12. The method of claim 10 wherein said adjusted combustion parameter is oxygen-containing gas flow rate.
13. The method of claim 10 wherein said adjusted combustion parameter is induction zone temperature.
14. The method of detecting changes in composition of a normally liquid hydrocarbon fraction which comprises:
(1) introducing a preheated vaporized stream of said hydrocarbon fraction and a preheated stream of air into one end of a combustion zone maintained at elevated temperature and under super-atmospheric pressure;
(2) therein partially oxidizing said hydrocarbon fraction under conditions to generate in said zone a stabilized cool flame characterized by a relatively narrow, well-defined flame front spaced from said one end;
(3) sensing the position of said flame front relative to said one end and developing therefrom a control signal;
(4) varying the pressure of said combustion zone responsive to said control signal in a manner to immobilize said flame front relative to said one end regardless of changes in composition of said hydrocarbon fraction; and
(5) sensing said combustion pressure and developing therefrom an output signal responsive to changes in said hydrocarbon composition.
15. The method of determining the octane rating of a gasoline fraction which comprises:
(1) introducing a preheated vaporized stream of said gasoline fraction and a preheated stream of air into one end of an elongated combustion zone maintained at elevated temperature and under superatmospheric pressure;
(2) commingling said streams at said one end and partially oxidizing said gasoline fraction within the combustion zone under conditions to generate in said zone a stabilized cool flame characterized by a relatively narrow, well-defined flame front spaced from said one end;
(3) sensing the position of said flame front relative to said one end and developing therefrom a control signal;
(4) varying the pressure of said combustion zone responsive to said control signal in a manner to immobilize said flame front relative to said one end regardless of changes in composition of said gasoline fraction; and
(5) sensing said combustion pressure and developing therefrom an output signal responsive to changes in said gasoline composition and correlatable with the octane rating thereof.
16. The method of claim 15 further characterized in that the temperature of the combustion zone upstream from said flame front is in the range of 550-850 F.
17. The method of claim 15 further characterized in 13 14 that the pressure of the combustion zone is in the range OTHER REFERENCES of 20455 Barusch, M. R. et al., Industrial and Engineering 18. The method of claim 15 further characterized in that the pressure of the combustion zone is in the range Chemlstry 2329 32 (19511) Of 255 P- 5 MORRIS O. WOLK, Primary Examiner References Cited ELLIOTT A. KATZ, Assistant Examiner UNITED STATES PATENTS 2,603,085 7/1952 Cannon. US. Cl. X.R. 3,262,486 7/1966 R086. 21 232 2g 25'4. 4';1 75 3,295,585 1/1967 Kayach et a1, l
US471670A 1965-07-13 1965-07-13 Hydrocarbon analyzer comprising stabilized cool flame generator with servo-positioned flame front Expired - Lifetime US3463613A (en)

Priority Applications (15)

Application Number Priority Date Filing Date Title
US471670A US3463613A (en) 1965-07-13 1965-07-13 Hydrocarbon analyzer comprising stabilized cool flame generator with servo-positioned flame front
IL26079A IL26079A (en) 1965-07-13 1966-07-03 Apparatus and method for analyzing hydrocarbons
GB29899/66A GB1084844A (en) 1965-07-13 1966-07-04 Apparatus and method for analyzing hydrocarbons
FR68704A FR1486188A (en) 1965-07-13 1966-07-08 Apparatus and method for analyzing hydrocarbons
AT659866A AT286941B (en) 1965-07-13 1966-07-08 Apparatus for the analysis of mixtures containing hydrocarbons and a process for the continuous adjustment of the octane number of a process stream containing hydrocarbons using the apparatus
DE1673172A DE1673172C3 (en) 1965-07-13 1966-07-11 Method for measuring the composition of hydrocarbon-containing mixtures and device therefor
ES0328961A ES328961A1 (en) 1965-07-13 1966-07-11 An apparatus to analyze hydrocarbons. (Machine-translation by Google Translate, not legally binding)
DK362566AA DK120669B (en) 1965-07-13 1966-07-12 Apparatus for detecting changes in the composition of a hydrocarbonaceous mixture.
NO163886A NO117052B (en) 1965-07-13 1966-07-12
NL666609823A NL144736B (en) 1965-07-13 1966-07-13 METHOD OF TRACKING THE CHANGE IN RESEARCH OCTA NUMBER OF A HYDROCARBON-CONTAINING ENGINE FUEL PRODUCT FLOW.
BR181272/66A BR6681272D0 (en) 1965-07-13 1966-07-13 APPARATUS AND PROCESS TO ANALYZE HYDROCARBONS
SE09596/66A SE335806B (en) 1965-07-13 1966-07-13
CH1020866A CH492219A (en) 1965-07-13 1966-07-13 Device for the analysis of hydrocarbon mixtures and their use
FI661876A FI47934C (en) 1965-07-13 1966-07-13 Method and device for detecting changes in hydrocarbon mixtures
JP4586466A JPS4513519B1 (en) 1965-07-13 1966-07-13

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JP (1) JPS4513519B1 (en)
AT (1) AT286941B (en)
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CH (1) CH492219A (en)
DE (1) DE1673172C3 (en)
DK (1) DK120669B (en)
ES (1) ES328961A1 (en)
FI (1) FI47934C (en)
FR (1) FR1486188A (en)
GB (1) GB1084844A (en)
IL (1) IL26079A (en)
NL (1) NL144736B (en)
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SE (1) SE335806B (en)

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US3533746A (en) * 1967-10-31 1970-10-13 Universal Oil Prod Co Method and apparatus for analyzing hydrocarbon compositions
US3533747A (en) * 1967-10-31 1970-10-13 Universal Oil Prod Co Method for determining motor octane number of a hydrocarbon sample
US3533745A (en) * 1967-10-31 1970-10-13 Universal Oil Prod Co Method for analyzing hydrocarbon compositions
US3607088A (en) * 1968-03-22 1971-09-21 Cobble Co Ltd Apparatus for simultaneously measuring temperature of reaction and pressure in vapor and liquid phases of very small amount of sample under pressure
US3649202A (en) * 1969-10-22 1972-03-14 Universal Oil Prod Co Control of reaction zone severity by response to octane number of effluent liquid phase
US3718577A (en) * 1971-07-16 1973-02-27 Mobil Oil Corp Control of hydrocracking process for constant conversion
US3926562A (en) * 1972-09-08 1975-12-16 Us Navy Vertical tube combustion reactor
US3929926A (en) * 1974-05-10 1975-12-30 Universal Oil Prod Co Method of controlling HF alkylation reaction temperature
US3937749A (en) * 1974-05-10 1976-02-10 Universal Oil Products Company Hf alkylation reaction temperature control
US3972957A (en) * 1974-12-19 1976-08-03 Universal Oil Products Company HF alkylation reaction temperature control system
FR2360120A1 (en) * 1976-07-30 1978-02-24 Uop Inc Control system for hydrocarbon hydroconversion processes - to monitor process parameters and regulate hydrogen hydrocarbon mole ratio
FR2360121A1 (en) * 1976-07-30 1978-02-24 Uop Inc Control system for hydrocarbon hydroconversion processes - monitoring process parameters and regulating hydrogen/hydrocarbon mole ratio
US4397958A (en) * 1981-09-08 1983-08-09 The Foxboro Company Hydrocarbon analysis
US20080213914A1 (en) * 2006-12-01 2008-09-04 Petroleum Analyzer Company, Lp Method and system for measuring ron and mon values for light distillates
US20160138827A1 (en) * 2014-11-13 2016-05-19 Miclau-S.R.I. Inc. Condensing water heater with dielectrically insulated secondary flue
US11047573B2 (en) * 2018-02-05 2021-06-29 Chevron Phillips Chemical Company Lp Flare monitoring and control method and apparatus

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FR2488694A1 (en) * 1980-08-14 1982-02-19 Electricite De France Determn. of paraffin content of heavy fuel oil - by analysis of explosions generated above the heated oil

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US2603085A (en) * 1947-08-19 1952-07-15 Emhart Mfg Co Means for and method of ascertaining combustion characteristics of premixtures
US3262486A (en) * 1964-08-07 1966-07-26 John J Rose Ultraviolet light responsive flame modulating control
US3295585A (en) * 1965-07-12 1967-01-03 American Gas Ass Apparatus for sensing the composition of gases, and gas burner system employing same

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US2603085A (en) * 1947-08-19 1952-07-15 Emhart Mfg Co Means for and method of ascertaining combustion characteristics of premixtures
US3262486A (en) * 1964-08-07 1966-07-26 John J Rose Ultraviolet light responsive flame modulating control
US3295585A (en) * 1965-07-12 1967-01-03 American Gas Ass Apparatus for sensing the composition of gases, and gas burner system employing same

Cited By (19)

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US3533746A (en) * 1967-10-31 1970-10-13 Universal Oil Prod Co Method and apparatus for analyzing hydrocarbon compositions
US3533747A (en) * 1967-10-31 1970-10-13 Universal Oil Prod Co Method for determining motor octane number of a hydrocarbon sample
US3533745A (en) * 1967-10-31 1970-10-13 Universal Oil Prod Co Method for analyzing hydrocarbon compositions
US3607088A (en) * 1968-03-22 1971-09-21 Cobble Co Ltd Apparatus for simultaneously measuring temperature of reaction and pressure in vapor and liquid phases of very small amount of sample under pressure
US3649202A (en) * 1969-10-22 1972-03-14 Universal Oil Prod Co Control of reaction zone severity by response to octane number of effluent liquid phase
US3718577A (en) * 1971-07-16 1973-02-27 Mobil Oil Corp Control of hydrocracking process for constant conversion
US3926562A (en) * 1972-09-08 1975-12-16 Us Navy Vertical tube combustion reactor
US3929926A (en) * 1974-05-10 1975-12-30 Universal Oil Prod Co Method of controlling HF alkylation reaction temperature
US3937749A (en) * 1974-05-10 1976-02-10 Universal Oil Products Company Hf alkylation reaction temperature control
US3972957A (en) * 1974-12-19 1976-08-03 Universal Oil Products Company HF alkylation reaction temperature control system
FR2360120A1 (en) * 1976-07-30 1978-02-24 Uop Inc Control system for hydrocarbon hydroconversion processes - to monitor process parameters and regulate hydrogen hydrocarbon mole ratio
FR2360121A1 (en) * 1976-07-30 1978-02-24 Uop Inc Control system for hydrocarbon hydroconversion processes - monitoring process parameters and regulating hydrogen/hydrocarbon mole ratio
US4397958A (en) * 1981-09-08 1983-08-09 The Foxboro Company Hydrocarbon analysis
US20080213914A1 (en) * 2006-12-01 2008-09-04 Petroleum Analyzer Company, Lp Method and system for measuring ron and mon values for light distillates
US8646312B2 (en) * 2006-12-01 2014-02-11 Petroleum Analyzer Company, Lp Method and system for measuring RON and MON values for light distillates
US20160138827A1 (en) * 2014-11-13 2016-05-19 Miclau-S.R.I. Inc. Condensing water heater with dielectrically insulated secondary flue
US10024574B2 (en) * 2014-11-13 2018-07-17 Miclau-S.R.I. Inc Condensing water heater with dielectrically insulated secondary flue
US11047573B2 (en) * 2018-02-05 2021-06-29 Chevron Phillips Chemical Company Lp Flare monitoring and control method and apparatus
US11598523B2 (en) 2018-02-05 2023-03-07 Chevron Phillips Chemical Company, Lp Flare monitoring and control method and apparatus

Also Published As

Publication number Publication date
GB1084844A (en) 1967-09-27
JPS4513519B1 (en) 1970-05-15
DE1673172C3 (en) 1974-10-17
AT286941B (en) 1970-12-28
FR1486188A (en) 1967-06-23
NO117052B (en) 1969-06-23
NL144736B (en) 1975-01-15
NL6609823A (en) 1967-01-16
DE1673172B2 (en) 1974-03-21
FI47934C (en) 1974-04-10
DK120669B (en) 1971-06-28
IL26079A (en) 1970-11-30
CH492219A (en) 1970-06-15
ES328961A1 (en) 1967-09-16
SE335806B (en) 1971-06-07
DE1673172A1 (en) 1972-01-20
BR6681272D0 (en) 1973-08-28
FI47934B (en) 1974-01-02

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