text:
perdĭtor, ōris, m. [perdo], a ruiner, destroyer (rare but class.): perditor rei publi cae, Cic. Planc. 36, 89; id. Vatin. 3, 7: vexa tor et perditor, id. Pis. 34, 84: afflictor et perditor ordinis, id. ib. 27, 64: hominum, Lact. 2, 14, 8.
per-do, dĭdi, ditum, 3 (old form of the pres. subj. perduim, Plaut. Aul. 4, 6, 6: perduis, id. Am. 2, 2, 215; id. Capt. 3, 5, 70: perduit, id. Ep. 1, 1, 64; id. Poen. 3, 4, 29; but esp. freq., perduint, Plaut. As. 2, 4, 61; id. Aul. 4, 10, 55; id. Curc. 5, 3, 41; id. Cas. 3, 5, 17; id. Most. 3, 1, 138; id. Men. 2, 2, 34; 3, 1, 6; 5, 5, 31; id. Merc. 4, 3, 11; 4, 4, 53; id. Poen. 3, 2, 33; 4, 2, 41; id. Stich. 4, 2, 15; id. Truc. 2, 3, 10; Ter. Heaut. 4, 6, 7; id. Hec. 3, 4, 27; id. Phorm. 1, 2, 73; Cic. Deiot. 7, 21; id. Att. 15, 4, 3.
As the pass. of perdo, only pereo, perditus, perire appear to be in good use.
The only classical example of a pass. form in the pres. is: perditur haec inter misero lux non sine votis, Hor. S. 2, 6, 59 (K. and H. ad loc.), where Lachm., perh. needlessly, reads lux porgitur, the day seems too long for me.
In the pass. perdi, in late Lat.; v. infra), v. a., to make away with; to destroy, ruin; to squander, dissipate, throw away, waste, lose, etc. (class.; syn.: dissipo, perimo, deleo).
I. Lit.: aliquem perditum ire, Plaut. Aul. 4, 10, 5: Juppiter fruges perdidit, Cic. Rosc. Am. 45, 131: funditus civitatem, id. Att. 6, 1, 5: se ipsum penitus, id. Fin. 1, 15, 49: perdere et affligere cives, id. Rosc. Am. 12, 33: perdere et pessundare aliquem, Plaut. Bacch. 3, 3, 3: aliquem capitis, i. e. to charge with a capital offence, id. As. 1, 2, 6; id. Bacch. 3, 3, 86: sumat, consumat, perdat, squander, Ter. Heaut. 3, 1, 56; so, perde et peri, Plaut. Truc. 5, 59: perdere et profundere, to waste, Cic. Fam. 5, 5, 3: perdere tempus, id. de Or. 3, 36, 146: operam, id. Mur. 10, 23; cf.: oleum et operam, id. Fam. 7, 1, 3: Decius amisit vitam: at non perdidit, Auct. Her. 4, 44, 57: cur perdis adulescentem nobis? cur amat? Cur potat? Ter. Ad. 1, 1, 36.
In execrations (very common): di (deaeque omnes) te perduint, may the gods destroy you! See the passages with perduint cited init.
Pass. (late Lat.): verbis perderis ipse tuis, Prosp. Epigr.: impii de terrā perdentur, Vulg. Prov. 2, 22: quasi sterquilinium in fine perdetur, id. Job, 20, 7.
II. Transf., in gen., to lose utterly or irrecoverably: eos (liberos), Cic. Fam. 5, 16, 3: omnes fructus industriae et fortunae, id. ib. 4, 6, 2: litem, to lose one’s cause, id. de Or. 1, 36, 167: libertatem, id. Rab. Post. 9, 24: dextram manum, Plin. 7, 28, 29, § 104: memoriam, Cic. Sen. 7, 21: causam, id. Rosc. Com. 4, 11: spem, Plaut. Rud. 1, 4, 3: vitam, Mart. Spect. 13, 2: perii hercle! nomen perdidi, i. e. I have quite forgotten the name, Ter. Phorm. 2, 3, 39.
Pass. (late Lat.): si principis vita perditur, Amm. 14, 5, 4; Hor. S. 2, 6, 59 (v. supra).
Of loss at play: ne perdiderit, non cessat perdere lusor, Ov. A. A. 1, 451; Juv. 1, 93.
A. Hopeless, desperate, ruined, past recovery (class.; syn. profligatus): perditus sum, i. q. perii, I am lost! Plaut. Bacch. 5, 1, 6; id. Rud. 5, 1, 3: per fortunas vide, ne puerum perditum perdamus, Cic. Fam. 14, 1, 5: perditus aere alieno, id. Phil. 2, 32, 78: lacrimis ac maerore perditus, id. Mur. 40, 86: tu omnium mortalium perditissime, id. Verr. 2, 3, 26, § 64: rebus omnibus perditis, id. Caecin. 31, 90: senatoria judicia, id. Verr. 1, 3, 8: valetudo, id. Tusc. 5, 10, 29.
2. In partic., desperately in love; lost, ruined by love (poet.): amore haec perdita est, Plaut. Cist. 1, 2, 13: in puellā, Prop. 1, 13, 7: amor, Cat. 89, 2.
B. Lost in a moral sense, abandoned, corrupt, profligate, flagitious, incorrigible: adulescens perditus ac dissolutus, Cic. Tusc. 4, 25, 55: homo contaminatus, perditus, flagitiosus, id. Verr. 2, 3, 58, § 134: abjecti homines et perditi, id. Mil. 18, 47; id. Cat. 1, 6, 9: homo perditā nequitiā, id. Clu. 13, 36: perdita atque dissoluta consilia, id. Agr. 2, 20, 55: luxuriae ac lasciviae perditae, Suet. Calig. 25: nihil fieri potest miserius, nihil perditius, nihil foedius, Cic. Att. 8, 11, 4; id. Q. Fr. 3, 9, 1; Cat. 42, 13.
Hence, sup.: omnium mortalium perditissimus, Cic. Verr. 2, 3, 26, § 65; Just. 21, 5, 5.
1. In an abandoned manner, incorrigibly: se gerere, Cic. Att. 9, 2, A, 2.
2. Desperately, excessively: amare, Ter. Phorm. 1, 2, 32: conari, Quint. 2, 12, 5.

matches:
v.
v.
in fine
§ 104
§ 64
§ 134
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text:
Methods and systems for low emission power generation in hydrocarbon recovery processes are provided. One system includes a gas turbine system configured to stoichiometrically combust a compressed oxidant derived from enriched air and a fuel in the presence of a compressed recycle exhaust gas and expand the discharge in an expander to generate a recycle exhaust stream and drive a main compressor. A boost compressor receives and increases the pressure of the recycle exhaust stream and prior to being compressed in a compressor configured to generate the compressed recycle exhaust gas. To promote the stoichiometric combustion of the fuel and increase the CO2 content in the recycle exhaust gas, the enriched air can have an increased oxygen concentration.
This application claims the benefit of U.S. provisional patent application No. 61/361,178, filed Jul. 2, 2010 entitled “Stoichiometric Combustion of Enriched Air With Exhaust Gas Recirculation”, the entirety of which is incorporated by reference herein.
This application contains subject matter related to U.S. Patent Application No. 61/361,169, filed Jul. 2, 2010 entitled “Systems and Methods for Controlling Combustion of a Fuel”; U.S. Patent Application No. 61/361,170, filed Jul. 2, 2010 entitled “Low Emission Triple-Cycle Power Generation Systems and Methods”; U.S. Patent Application No. 61/361,173, filed Jul. 2, 2010, entitled “Low Emission Triple-Cycle Power Generation Systems and Methods”; U.S. Patent Application No. 61/361,176, filed Jul. 2, 2010, entitled “Stoichiometric Combustion With Exhaust Gas Recirculation and Direct Contact Cooler”; U.S. Patent Application No. 61/361,180 filed Jul. 2, 2010, entitled “Low Emission Power Generation Systems and Methods”.
Embodiments of the disclosure relate to low emission power generation in combined-cycle power systems. More particularly, embodiments of the disclosure relate to methods and apparatus for combusting a fuel for enhanced carbon dioxide (CO2) manufacture and capture.
With the growing concern on global climate change and the impact of CO2 emissions, emphasis has been placed on CO2 capture from power plants. This concern combined with the implementation of cap-and-trade policies in many countries make reducing CO2 emissions a priority for these and other countries as well as the companies that operate hydrocarbon production systems therein.
Gas turbine combined-cycle power plants are rather efficient and can be operated at relatively low cost when compared to other technologies, such as coal and nuclear. Capturing CO2 from the exhaust of gas turbine combined-cycle plants, however, can be difficult for several reasons. For instance, there is typically a low concentration of CO2 in the exhaust compared to the large volume of gas that must be treated. Also, additional cooling is often required before introducing the exhaust to a CO2 capture system and the exhaust can become saturated with water after cooling, thereby increasing the reboiler duty in the CO2 capture system. Other common factors can include the low pressure and large quantities of oxygen frequently contained in the exhaust. All of these factors result in a high cost of CO2 capture from gas turbine combined-cycle power plants.
At least one approach to lowering CO2 emissions in combined-cycle systems includes stoichiometric combustion and exhaust gas recirculation. In a conventional exhaust gas recirculation system, such as a natural gas combined cycle (NGCC), a recycled component of the exhaust gas is mixed with ambient air and introduced into the compressor section of a gas turbine. Typical CO2 concentrations in the exhaust of a NGCC are around 3%-4%, but can increase above 4% with exhaust recirculation. In operation, conventional NGCC systems require only about 40% of the air intake volume to provide adequate stoichiometric combustion of the fuel, while the remaining 60% of the air volume serves as a diluent to moderate the temperature and cool the exhaust to a temperature suitable for introduction into the succeeding expander. Recirculating a portion of the exhaust gas increases the CO2 concentration in the exhaust, which can subsequently be used as the diluent in the combustion system.
However, due to the molecular weight, specific heat, Mach number effects, etc. of CO2, without significant modifications to either the compressor or the expander sections, standard gas turbines are limited as to the concentration of CO2 that can be tolerated in the compression section of the gas turbine from the exhaust. For example, the limit on CO2 content in the exhaust recirculated to the compression section of a standard gas turbine is about 20 wt % CO2.
Moreover, the typical NGCC system produces low pressure exhaust which requires a fraction of the power produced via expansion of the exhaust in order to extract the CO2 for sequestration or enhanced oil recovery (EOR), thereby reducing the thermal efficiency of the NGCC. Further, the equipment for the CO2 extraction is large and expensive, and several stages of compression are required to take the ambient pressure gas to the pressure required for EOR or sequestration. Such limitations are typical of post-combustion carbon capture from low pressure exhaust associated with the combustion of other fossil fuels, such as coal.
The foregoing discussion of need in the art is intended to be representative rather than exhaustive. A technology addressing one or more such needs, or some other related shortcoming in the field, would benefit power generation in combined-cycle power systems.
The present disclosure is directed to integrated systems and methods for improving power generation systems. In some implementations, the present disclosure provides a gas turbine system, comprising a first compressor, a second compressor, a combustion chamber, and an expander. The first compressor may be configured to receive and compress a recycled exhaust gas into a compressed recycle exhaust gas. The second compressor may be configured to receive and compress enriched air to generate a compressed oxidant. The combustion chamber may be configured to receive the compressed recycle exhaust gas and the compressed oxidant and to stoichiometrically combust a fuel stream. The compressed recycle exhaust gas serves as a diluent to moderate combustion temperatures. The expander may be configured to receive a discharge from the combustion chamber to generate the recycled exhaust gas. The expander further may be coupled to the first compressor to drive, at least partially, the first compressor.
Additionally or alternatively, the present disclosure provides methods of generating power. Exemplary methods include: a) compressing a recycled exhaust gas in a main compressor to generate a compressed recycle exhaust gas; b) compressing enriched air in an inlet compressor to generate a compressed oxidant; c) stoichiometrically combusting the compressed oxidant and a fuel in a combustion chamber and in the presence of the compressed recycle exhaust gas, thereby generating a discharge stream, wherein the compressed recycle exhaust gas acts as a diluent configured to moderate the temperature of the discharge stream; and d) expanding the discharge stream in an expander to at least partially drive the main compressor and generate the recycled exhaust gas and at least partially drive the main compressor.
Still additionally or alternatively, the present disclosure provides integrated power generation systems. Exemplary integrated power generation systems include both a gas turbine system and an exhaust gas recirculation system. The gas turbine system may comprise a first compressor, a second compressor, a combustion chamber, and an expander. The first compressor may be configured to receive and compress a recycled exhaust gas into a compressed recycle exhaust gas. The second compressor may be configured to receive and compress enriched air to generate a compressed oxidant, the enriched air having an oxygen concentration between about 30 wt % and about 50 wt %. The combustion chamber may be configured to receive the compressed recycle exhaust gas and the compressed oxidant and to stoichiometrically combust a fuel stream, wherein the compressed recycle exhaust gas serves as a diluent to moderate combustion temperatures. The expander may be configured to receive a discharge from the combustion chamber to generate the recycled exhaust stream. The expander further may be coupled to the first compressor and adapted to drive, at least partially, the first compressor. The exhaust gas recirculation system may include a heat recovery steam generator, one or more cooling units, and a boost compressor. The heat recovery steam generator may be communicably coupled to a steam gas turbine. The heat recovery steam generator may be being configured to receive the exhaust gas from the expander to create steam that generates electrical power in the steam generator. The one or more cooling units may be configured to cool the recycled exhaust gas received from the heat recovery steam generator and to remove condensed water from the recycled exhaust gas. The boost compressor may be configured to increase the pressure of the recycled exhaust gas before injection into the first compressor to provide the compressed recycle exhaust gas.
FIG. 1 depicts a schematic of an integrated system for low emission power generation and enhanced CO2 recovery, according to one or more embodiments described.
FIG. 2 depicts another schematic of an integrated system for low emission power generation and enhanced CO2 recovery, according to one or more embodiments described.
FIG. 3 depicts another schematic of an integrated system for low emission power generation and enhanced CO2 recovery, according to one or more embodiments described.
As used herein, the term “natural gas” refers to a multi-component gas obtained from a crude oil well (associated gas) or from a subterranean gas-bearing formation (non-associated gas). The composition and pressure of natural gas can vary significantly. A typical natural gas stream contains methane (CH4) as a major component, i.e. greater than 50 mol % of the natural gas stream is methane. The natural gas stream can also contain ethane (C2H6), higher molecular weight hydrocarbons (e.g., C3-C20 hydrocarbons), one or more acid gases (e.g., hydrogen sulfide, carbon dioxide), or any combination thereof. The natural gas can also contain minor amounts of contaminants such as water, nitrogen, iron sulfide, wax, crude oil, or any combination thereof.
As used herein, the term “stoichiometric combustion” refers to a combustion reaction having a volume of reactants comprising a fuel and an oxidizer and a volume of products formed by combusting the reactants where the entire volume of the reactants is used to form the products. As used herein, the term “substantially stoichiometric combustion” refers to a combustion reaction having a molar ratio of combustion fuel to oxygen ranging from about plus or minus 10% of the oxygen required for a stoichiometric ratio or more preferably from about plus or minus 5% of the oxygen required for the stoichiometric ratio. For example, the stoichiometric ratio of fuel to oxygen for methane is 1:2 (CH4+2O2>CO2+2H2O). Propane will have a stoichiometric ratio of fuel to oxygen of 1:5. Another way of measuring substantially stoichiometric combustion is as a ratio of oxygen supplied to oxygen required for stoichiometric combustion, such as from about 0.9:1 to about 1.1:1, or more preferably from about 0.95:1 to about 1.05:1.
Embodiments of the presently disclosed systems and processes can be used to produce ultra low emission electric power and CO2 for enhanced oil recovery (EOR) and/or sequestration applications. In one or more embodiments, a mixture of enriched air and fuel can be stoichiometrically or substantially stoichiometrically combusted and simultaneously mixed with a stream of recycled exhaust gas. The stream of recycled exhaust gas, generally including products of combustion such as CO2, can be used as a diluent to control, adjust, or otherwise moderate the temperature of combustion and the exhaust that enters the succeeding expander. As a result of using enriched air, the recycled exhaust gas can have an increased CO2 content, thereby allowing the expander to operate at even higher expansion ratios for the same inlet and discharge temperatures, thereby producing significantly increased power.
Combustion in commercial gas turbines at stoichiometric conditions or substantially stoichiometric conditions (e.g., “slightly rich” combustion) can prove advantageous in order to eliminate the cost of excess oxygen removal. By cooling the exhaust and condensing the water out of the cooled exhaust stream, a relatively high content CO2 exhaust stream can be produced. While a portion of the recycled exhaust gas can be utilized for temperature moderation in the closed Brayton cycle, a remaining purge stream can be used for EOR applications and/or electric power can be produced with little or no sulfur oxides (SOX), nitrogen oxides (NOx), and/or CO2 being emitted to the atmosphere. The result of this process is the production of power in three separate cycles and the manufacturing of additional CO2.
Referring now to the figures, FIG. 1 depicts a schematic of an illustrative integrated system 100 for power generation and CO2 recovery using a combined-cycle arrangement, according to one or more embodiments. In at least one embodiment, the power generation system 100 can include a gas turbine system 102 characterized as a power-producing, closed Brayton cycle. The gas turbine system 102 can have a first or main compressor 104 coupled to an expander 106 via a shaft 108. The shaft 108 can be any mechanical, electrical, or other power coupling, thereby allowing a portion of the mechanical energy generated by the expander 106 to drive the main compressor 104. In at least one embodiment, the gas turbine system 102 can be a standard gas turbine, where the main compressor 104 and expander 106 form the compressor and expander ends, respectively. In other embodiments, however, the main compressor 104 and expander 106 can be individualized components in the system 102.
The gas turbine system 102 can also include a combustion chamber 110 configured to combust a fuel introduced via line 112 and mixed with an oxidant introduced via line 114. In one or more embodiments, the fuel in line 112 can include any suitable hydrocarbon gas or liquid, such as natural gas, methane, ethane, naphtha, butane, propane, syngas, diesel, kerosene, aviation fuel, coal derived fuel, bio-fuel, oxygenated hydrocarbon feedstock, or any combinations thereof. The oxidant via line 114 can be derived from a second or inlet compressor 118 fluidly coupled to the combustion chamber 110 and adapted to compress a feed oxidant introduced via line 120. In one or more embodiments, the feed oxidant in line 120 can include atmospheric air, enriched air, or combinations thereof. When the oxidant in line 114 includes a mixture of atmospheric air and enriched air, the enriched air can be compressed by the inlet compressor 118 either before or after being mixed with the atmospheric air. The enriched air can have an overall oxygen concentration of about 30 wt %, about 35 wt %, about 40 wt %, about 45 wt %, or about 50 wt %.
The enriched air can be derived from several sources, including implementing various technologies upstream of the inlet compressor 118 to produce the enriched air. For example, the enriched air can be derived from such separation technologies as membrane separation, pressure swing adsorption, temperature swing adsorption, nitrogen plant-by-product streams, and/or combinations thereof. The enriched air can also be derived from an air separation unit (ASU), such as a cryogenic ASU, for producing nitrogen for pressure maintenance or other purposes. The reject stream from the ASU can be rich in oxygen, having an overall oxygen content of about 50 wt % to about 70 wt %. This reject stream can be used as at least a portion of the enriched air and subsequently diluted, if needed, with unprocessed atmospheric air to obtain the desired oxygen concentration for the application.
As will be described in more detail below, the combustion chamber 110 can also receive a compressed recycle exhaust gas in line 144, including an exhaust gas recirculation primarily having CO2 and nitrogen components. The compressed recycle exhaust gas in line 144 can be derived from the main compressor 104 and adapted to help facilitate a stoichiometric or substantially stoichiometric combustion of the compressed oxidant in line 114 and fuel in line 112 by moderating the temperature of the combustion products. As can be appreciated, recirculating the exhaust gas can serve to increase the CO2 concentration in the exhaust gas.
An exhaust gas in line 116 directed to the inlet of the expander 106 can be generated as a product of combustion of the fuel in line 112 and the compressed oxidant in line 114, in the presence of the compressed recycle exhaust gas in line 144. In at least one embodiment, the fuel in line 112 can be primarily natural gas, thereby generating a discharge or exhaust gas via line 116 that can include volumetric portions of vaporized water, CO2, nitrogen, nitrogen oxides (NOx), and sulfur oxides (SOx). In some embodiments, a small portion of unburned fuel in line 112 or other compounds can also be present in the exhaust gas in line 116 due to combustion equilibrium limitations. As the exhaust gas in line 116 expands through the expander 106 it generates mechanical power to drive the main compressor 104, an electrical generator, or other facilities, and also produces a gaseous exhaust in line 122 having a heightened CO2 content resulting from the influx of the compressed recycle exhaust gas in line 144. In some implementations the expander 106 may be adapted to produce additional mechanical power that may be used for other purposes.
The power generation system 100 can also include an exhaust gas recirculation (EGR) system 124. In one or more embodiments, the EGR system 124 can include a heat recovery steam generator (HRSG) 126, or similar device, fluidly coupled to a steam gas turbine 128. In at least one embodiment, the combination of the HRSG 126 and the steam gas turbine 128 can be characterized as a power-producing closed Rankine cycle. In combination with the gas turbine system 102, the HRSG 126 and the steam gas turbine 128 can form part of a combined-cycle power generating plant, such as a natural gas combined-cycle (NGCC) plant. The gaseous exhaust in line 122 can be introduced to the HRSG 126 in order to generate steam via line 130 and a cooled exhaust gas in line 132. In one embodiment, the steam in line 130 can be sent to the steam gas turbine 128 to generate additional electrical power.
The cooled exhaust gas in line 132 can be sent to a first cooling unit 134 adapted to cool the cooled exhaust gas in line 132 and generate a cooled recycle gas stream 140. The first cooling unit 134 can include, for example, one or more contact coolers, trim coolers, evaporative cooling unit, or any combination thereof. The first cooling unit 134 can also be adapted to remove a portion of any condensed water from the cooled exhaust gas in line 132 via a water dropout stream 138. In at least one embodiment, the water dropout stream 138 may be routed to the HRSG 126 via line 141 to provide a water source for the generation of additional steam in line 130 therein. In other embodiments, the water recovered via the water dropout stream 138 can be used for other downstream applications, such as supplementary heat exchanging processes.
In one or more embodiments, the cooled recycle gas stream 140 can be directed to a boost compressor 142. Cooling the cooled exhaust gas in line 132 in the first cooling unit 134 can reduce the power required to compress the cooled recycle gas stream 140 in the boost compressor 142. As opposed to a conventional fan or blower system, the boost compressor 142 can be configured to compress and increase the overall density of the cooled recycle gas stream 140, thereby directing a pressurized recycle gas in line 145 downstream, where the pressurized recycle gas in line 145 has an increased mass flow rate for the same volumetric flow. This can prove advantageous since the main compressor 104 can be volume-flow limited, and directing more mass flow through the main compressor 104 can result in higher discharge pressures, thereby translating into higher pressure ratios across the expander 106. Higher pressure ratios generated across the expander 106 can allow for higher inlet temperatures and, therefore, an increase in expander 106 power and efficiency. As can be appreciated, this may prove advantageous since the CO2-rich exhaust gas in line 116 generally maintains a higher specific heat capacity.
Since the suction pressure of the main compressor 104 is a function of its suction temperature, a cooler suction temperature will demand less power to operate the main compressor 104 for the same mass flow. Consequently, the pressurized recycle gas in line 145 can optionally be directed to a second cooling unit 136. The second cooling unit 136 can include, for example, one or more direct contact coolers, trim coolers, evaporative cooling units, or any combination thereof. In at least one embodiment, the second cooling unit 136 can serve as an aftercooler adapted to remove at least a portion of the heat of compression generated by the boost compressor 142 on the pressurized recycle gas in line 145. The second cooling unit 136 can also extract additional condensed water via a water dropout stream 143. In one or more embodiments, the water dropout streams 138, 143 can converge into stream 141 and may or may not be routed to the HRSG 126 to generate additional steam via line 130 therein.
While only first and second cooling units 134, 136 are depicted herein, it will be appreciated that any number of cooling units can be employed to suit a variety of applications, without departing from the scope of the disclosure. In fact, contemplated herein are embodiments where the cooled exhaust gas in line 132 is further directed to an evaporative cooling unit associated with the exhaust gas recirculation loop, such as generally described in the concurrently filed U.S. patent application entitled “Stoichiometric Combustion with Exhaust Gas Recirculation and Direct Contact Cooler,” the contents of which are hereby incorporated by reference to the extent not inconsistent with the present disclosure. As described therein, the exhaust gas recirculation system may include any variety of equipment adapted to provide the exhaust gas to the main compressor for injection into the combustion chamber.
The main compressor 104 can be configured to receive and compress the pressurized recycle gas in line 145 to a pressure nominally at or above the pressure of the combustion chamber 110, thereby generating the compressed recycle exhaust gas in line 144. As can be appreciated, cooling the pressurized recycle gas in line 145 in the second cooling unit 136 after compression in the boost compressor 142 can allow for an increased volumetric mass flow of exhaust gas into the main compressor 104. Consequently, this can reduce the amount of power required to compress the pressurized recycle gas in line 145 to a predetermined pressure.
In at least one embodiment, a purge stream 146 can be recovered from the compressed recycle exhaust gas in line 144 and subsequently treated in a CO2 separator 148 to capture CO2 at an elevated pressure via line 150. The separated CO2 in line 150 can be used for sales, used in another processes requiring CO2, and/or further compressed and injected into a terrestrial reservoir for enhanced oil recovery (EOR), sequestration, or another purpose. Because of the stoichiometric or substantially stoichiometric combustion of the fuel in line 112 combined with a boosted pressure from the boost compressor 142, the CO2 partial pressure in the purge stream 146 can be much higher than in conventional gas turbine exhausts. As a result, carbon capture in the CO2 separator 148 can be undertaken using low-energy separation processes, such as employing less energy-intensive solvents. At least one suitable solvent is potassium carbonate (K2CO3) which absorbs SOx and/or NOR, and converts them to useful compounds, such as potassium sulfite (K2SO3), potassium nitrate (KNO3), and other simple fertilizers. Exemplary systems and methods of using potassium carbonate for CO2 capture can be found in the concurrently filed U.S. patent application entitled “Low Emission Triple-Cycle Power Generation Systems and Methods,” the contents of which are hereby incorporated by reference to the extent not inconsistent with the present disclosure.
A residual stream 151, essentially depleted of CO2 and consisting primarily of nitrogen, can also be derived from the CO2 separator 148. In one or more embodiments, the residual stream 151 can be introduced to a gas expander 152 to provide power and an expanded depressurized gas, or exhaust gas, via line 156. The expander 152 can be, for example, a power-producing nitrogen expander. As depicted, the gas expander 152 can be optionally coupled to the inlet compressor 118 through a common shaft 154 or other mechanical, electrical, or other power coupling, thereby allowing a portion of the power generated by the gas expander 152 to drive the inlet compressor 118. However, during start-up of the system 100 and/or during normal operation when the gas expander 152 is unable to supply all the required power to operate the inlet compressor 118, at least one motor 158, such as an electric motor, can be used synergistically with the gas expander 152. For instance, the motor 158 can be sensibly sized such that during normal operation of the system 100, the motor 158 can be configured to supply the power short-fall from the gas expander 152. In other embodiments, however, the gas expander 152 can be used to provide power to other applications, and not directly coupled to the inlet compressor 118. For example, there may be a substantial mismatch between the power generated by the expander 152 and the requirements of the compressor 118. In such cases, the expander 152 could be adapted to drive a smaller (or larger) compressor (not shown) that demands less (or more) power.
An expanded depressurized gas in line 156, primarily consisting of dry nitrogen gas, can be discharged from the gas expander 152. In at least one embodiment, the combination of the gas expander 152, inlet compressor 118, and CO2 separator 148 can be characterized as an open Brayton cycle, or a third power-producing component of the power generation system 100. Illustrative systems and methods of expanding the nitrogen gas in the residual stream 151, and variations thereof, can be found in the concurrently filed U.S. patent application entitled “Low Emission Triple-Cycle Power Generation Systems and Methods,” the contents of which are hereby incorporated by reference to the extent not inconsistent with the present disclosure.
Referring now to FIG. 2, depicted is another schematic of an illustrative integrated system 200 for power generation and CO2 recovery using a combined-cycle arrangement, according to one or more embodiments. The system 200 of FIG. 2 is substantially similar to the system 100 of FIG. 1 and therefore will not be discussed in detail where like elements correspond to like numerals. The system 200 of FIG. 2, however, can replace the gas expander 152 of system 100 with a downstream compressor 158 configured to compress the residual stream 151 and generate a compressed exhaust gas via line 160. In one or more embodiments, the compressed exhaust gas in line 160 can be suitable for injection into a reservoir for pressure maintenance applications. In applications where methane gas is typically reinjected into hydrocarbon wells to maintain well pressures, compressing the residual stream 151 may prove advantageous. For example, the pressurized nitrogen gas in line 160 can instead be injected into the hydrocarbon wells and any residual methane gas can be sold or otherwise used as a fuel in related applications, such as providing fuel in line 112.
Referring to FIG. 3, depicted is another schematic of an illustrative integrated system 300 for power generation and CO2 recovery using a combined-cycle arrangement, according to one or more embodiments. The system 300 of FIG. 3 is substantially similar to the systems 100 and 200 of FIGS. 1 and 2, respectively, and therefore will not be discussed in detail where like elements correspond to like numerals. As depicted, the system 300 can be a characterized as a hybrid arrangement of the power-producing nitrogen gas expander 152 as discussed with reference to FIG. 1, and the pressure maintenance downstream compressor 158 as discussed with reference to FIG. 2. In one or more embodiments, the residual stream 151 can be split, thereby directing a first portion of the residual stream 151 to the gas expander 152, and at the same time directing a second portion of the residual stream 151 to the downstream compressor 158 via line 162. In at least one embodiment, the respective volumetric mass flow of the first and second portions can be manipulated so as to provide predetermined and/or desired amounts of the residual stream 151 to either location to maximize production.
By using enriched air as the compressed oxidant in line 114 and pressurizing the exhaust gas in the boost compressor 142, the power generation system 100 can achieve higher concentrations of CO2 in the exhaust gas, thereby allowing for more effective CO2 separation and capture. Embodiments disclosed herein can effectively increase the concentration of CO2 in the exhaust gas in line 116 to CO2 concentrations ranging from about 10 wt % to about 20 wt %. To achieve such CO2 concentrations, the combustion chamber 110 can be adapted to stoichiometrically or substantially stoichiometrically combust an incoming mixture of fuel in line 112 and compressed oxidant in line 114, where the compressed oxidant in line 114 includes enriched air having an overall oxygen concentration of about 30 wt %, about 35 wt %, about 40 wt %, about 45 wt %, or about 50 wt %.
In order to moderate the temperature of the stoichiometric combustion and meet expander 106 inlet temperature and component cooling requirements, a portion of the exhaust gas with increased CO2 content derived from the compressed recycle exhaust gas in line 144 can be injected into the combustion chamber 110 as a diluent. Thus, embodiments of the disclosure can essentially eliminate excess oxygen from the exhaust gas in line 116 while also increasing its CO2 concentration to about 20 wt %. As such, the gaseous exhaust in line 122 can have less than about 3.0 wt % oxygen, or less than about 1.0 wt % oxygen, or less than about 0.1 wt % oxygen, or even less than about 0.001 wt % oxygen.
At least one benefit of having an increased CO2 concentration is that the expander 106 can be operated at an even higher expansion ratio for the same inlet and discharge temperatures, and thereby produce increased power. This is due to the higher heat capacity of CO2 relative to nitrogen found in ambient air. In one or more embodiments, the expansion ratio of the expander 106 can be increased from about 17.0 to about 20.0 corresponding to about 10 wt % and about 20 wt % CO2 recycle streams, respectively. Embodiments using enriched air having about 35 wt % oxygen can be used in order to achieve the about 20 wt % in the CO2 recycle stream.
Other benefits of having an increased CO2 concentration in the recycle gas include an increased concentration of CO2 in the extracted purge stream 146 used for CO2 separation. Because of its increased CO2 concentration, the purge stream 146 need not be as large in order to extract the required amounts of CO2. For example, the equipment handling extraction for CO2 separation can be smaller, including its piping, heat exchangers, valves, absorber towers, etc. Moreover, increased concentrations of CO2 can improve the performance of CO2 removal technology, including using low-energy separation processes, such as employing less energy-intensive solvents that would otherwise be untenable. Consequently, capital expenditures for capturing CO2 can be dramatically lowered.
The specifics of exemplary operation of the system 100 will now be discussed. As will be appreciated, specific temperatures and pressures achieved or experienced in the various components of any of the embodiments disclosed herein can change depending on, among other factors, the purity of the oxidant used and/or the specific makes and/or models of expanders, compressors, coolers, etc. Accordingly, it will be appreciated that the particular data described herein is for illustrative purposes only and should not be construed as the only interpretation thereof. In an embodiment, the inlet compressor 118 can provide compressed oxidant in line 114 at pressures ranging between about 280 psia and about 300 psia. Also contemplated herein, however, is aeroderivative gas turbine technology, which can produce and consume pressures of up to about 750 psia and more.
The main compressor 104 can be configured to recycle and compress recycled exhaust gas into the compressed recycle exhaust gas in line 144 at a pressure nominally above or at the combustion chamber 110 pressure, and use a portion of that recycled exhaust gas as a diluent in the combustion chamber 110. Because amounts of diluent needed in the combustion chamber 110 can depend on the purity of the oxidant used for stoichiometric combustion or the particular model or design of expander 106, a ring of thermocouples and/or oxygen sensors (not shown) can be disposed on the outlet of the expander 106. In operation, the thermocouples and sensors can be adapted to regulate and determine the volume of exhaust gas required as diluent needed to cool the products of combustion to the required expander inlet temperature, and also regulate the amount of oxidant being injected into the combustion chamber 110. Thus, in response to the heat requirements detected by the thermocouples and the oxygen levels detected by the oxygen sensors, the volumetric mass flow of compressed recycle exhaust gas in line 144 and compressed oxidant in line 114 can be manipulated or fluctuate to match the demand. Illustrative embodiments and more detailed descriptions of systems and methods for controlling the composition of an exhaust gas produced by combusting a fuel can be found in the concurrently filed U.S. patent application entitled “Systems and Methods for Controlling Combustion of a Fuel,” the contents of which are hereby incorporated by reference to the extent not inconsistent with the present disclosure.
In at least one embodiment, a pressure drop of about 12-13 psia can be experienced across the combustion chamber 110 during stoichiometric or substantially stoichiometric combustion. Combustion of the fuel in line 112 and the compressed oxidant in line 114 can generate temperatures between about 2000° F. and about 3000° F. and pressures ranging from 250 psia to about 300 psia. As described above, because of the increased mass flow and higher specific heat capacity of the CO2-rich exhaust gas derived from the compressed recycle exhaust gas in line 144, higher pressure ratios can be achieved across the expander 106, thereby allowing for higher inlet temperatures and increased expander 106 power.
The gaseous exhaust in line 122 exiting the expander 106 can exhibit pressures at or near ambient. In at least one embodiment, the gaseous exhaust in line 122 can have a pressure of about 13-17 psia. The temperature of the gaseous exhaust in line 122 can be about 1225° F. to about 1275° F. before passing through the HRSG 126 to generate steam in line 130 and a cooled exhaust gas in line 132. In one or more embodiments, the cooling unit 134 can reduce the temperature of the cooled exhaust gas in line 132 thereby generating the cooled recycle gas stream 140 having a temperature between about 32° F. and about 120° F. As can be appreciated, such temperatures can fluctuate depending primarily on wet bulb temperatures during specific seasons in specific locations around the globe.
According to one or more embodiments, the boost compressor 142 can be configured to elevate the pressure of the cooled recycle gas stream 140 to a pressure ranging from about 17 psia to about 21 psia. As a result, the main compressor 104 eventually receives and compresses a recycled exhaust with a higher density and increased mass flow, thereby allowing for a substantially higher discharge pressure while maintaining the same or similar pressure ratio. In order to further increase the density and mass flow of the recycle exhaust gas, the pressurized recycle gas in line 145 discharged from the boost compressor 142 can then be further cooled in the second cooling unit 136. In one or more embodiments, the second cooling unit 136 can be configured to reduce the temperature of the pressurized recycle gas in line 145 to about 105° F. before being directed to the main compressor 104.
In at least one embodiment, the temperature of the compressed recycle exhaust gas in line 144 discharged from the main compressor 104, and consequently the temperature of the purge stream 146, can be about 800° F., with a pressure of around 280 psia. The addition of the boost compressor 142 and the stoichiometric combustion of enriched air can increase the CO2 purge pressure in the purge stream 146, which can lead to improved solvent treating performance in the CO2 separator 148 due to the higher CO2 partial pressure.
Embodiments of the present disclosure can be further described with the following simulated example. Although the simulated example is directed to a specific embodiment, it is not to be viewed as limiting the disclosure in any specific respect.
To illustrate the superior performance of using enriched air as the compressed oxidant in line 114, the system 100 was simulated using standard air and then using enriched air having an oxygen concentration of about 35 wt % for the same gas turbine system 102 under the same ambient conditions. The following table provides these testing results and performance estimations.
As should be apparent from Table 1, embodiments including enriched air as the compressed oxidant in line 114 can result in an increase in expander 106 power, due to an increased expansion pressure ratio and an increased mass flow through the expander 106. Moreover, while the main compressor 104 may experience a slight increase in power demand, partially arising from the removal of a portion of the N2 component from the air, the increase is more than offset by the reduced air compression power in the inlet compressor 118, thereby resulting in an overall decrease in the total compression power required. As can be appreciated, because of the reduced airflow for the same amount of oxygen, the inlet compressor 118 can exhibit a considerable decrease in required compressor power. Importantly, Table 1 indicates a large increase in the combined-cycle power output which reflects about 1.0% uplift in combined-cycle efficiency.
While the present disclosure may be susceptible to various modifications and alternative forms, the exemplary embodiments discussed above have been shown only by way of example. However, it should again be understood that the disclosure is not intended to be limited to the particular embodiments disclosed herein. Indeed, the present disclosure includes all alternatives, modifications, and equivalents falling within the true spirit and scope of the appended claims.
an expander coupled to the first compressor and configured to receive a discharge from the combustion chamber to generate the recycled exhaust gas and at least partially drive the first compressor.
2. The system of claim 1, wherein the enriched air has an oxygen concentration between about 30 wt % and about 50 wt %.
3. The system of claim 2, wherein the enriched air is mixed with atmospheric air to obtain the oxygen concentration between about 30 wt % and about 50 wt %.
4. The system of claim 1, wherein the enriched air is derived from membrane separation, pressure swing adsorption, temperature swing adsorption, and any combination thereof.
5. The system of claim 1, wherein the enriched air is derived from a reject stream of an air separation unit.
6. The system of claim 5, wherein the reject stream has an oxygen concentration between about 50 wt % and about 70 wt %.
7. The system of claim 1, wherein the recycle exhaust gas has a CO2 concentration of between about 10 wt % and about 20 wt %.
8. The system of claim 1, wherein the fuel stream is selected from the group consisting of: natural gas, methane, naphtha, butane, propane, syngas, diesel, kerosene, aviation fuel, coal derived fuel, bio-fuel, oxygenated hydrocarbon feedstock, and any combination thereof.
9. The system of claim 1, further comprising a purge stream taken from the compressed recycle exhaust gas and treated in a CO2 separator to generate a CO2 stream and a residual stream substantially comprising nitrogen gas.
expanding the discharge stream in an expander to at least partially drive the main compressor and generate the recycled exhaust gas and at least partially drive the main compressor.
11. The method of claim 10, wherein the enriched air has an oxygen concentration between about 30 wt % and about 50 wt %.
12. The method of claim 11, further comprising mixing the enriched air with atmospheric air to obtain the oxygen concentration between about 30 wt % and about 50 wt %.
13. The method of claim 10, wherein the recycle exhaust gas has a CO2 concentration of between about 10 wt % and about 20 wt %.
14. The method of claim 10, wherein the enriched air is derived from a reject stream of an air separation unit, the reject stream having an oxygen concentration between about 50 wt % and about 70 wt %.
a boost compressor configured to increase the pressure of the recycled exhaust gas before injection into the first compressor to provide the compressed recycle exhaust gas.
16. The system of claim 15, wherein the boost compressor increases the pressure of the recycled exhaust gas stream to a pressure between about 17 psia and about 21 psia.
17. The system of claim 15, wherein the recycle exhaust gas has a CO2 concentration of between about 15 wt % and about 20 wt %.
18. The system of claim 15, wherein the enriched air is mixed with atmospheric air to obtain the oxygen concentration between about 30 wt % and about 50 wt %.
19. The system of claim 15, wherein the enriched air is derived from membrane separation, pressure swing adsorption, temperature swing adsorption, an air separation unit, and any combination thereof.
20. The system of claim 19, wherein the air separation unit has a reject stream having an oxygen concentration between about 50 wt % and about 70 wt %, the reject stream substantially providing the enriched air.
MX2017016478A (en) * 2015-06-15 2018-05-17 8 Rivers Capital Llc System and method for startup of a power production plant.

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application No. 61
Application No. 61
Application No. 61
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Application No. 61


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Sims v. Albertson, LLC et al, No. 1:16-cv-10553 (D. Mass.): Copycat putative class action asserting claims for breach of warranty (express and implied merchantability), and unjust enrichment. Plaintiff alleges Defendants have falsely advertised their grated parmesan cheese products as containing “100% parmesan cheese,” when the products contain significant amounts of adulterants and fillers, including cellulose, a filler and anti-clumping agent derived from wood pulp. Complaint.
McCartney v. Trader Joe’s Co., No. CGC-16-551071 (Cal. Super. Ct. – San Francisco Cnty.): Proposition 65 action alleging Defendant’s unsweetened cocoa powder contains cadmium. Complaint.
Giffin v. Universal Protein Supplement Corp., No. BC613414 (Cal. Super. Ct. – Los Angeles Cnty.): Putative class action asserting violations of California’s consumer protection statutes and claims for negligent and intentional misrepresentation. Plaintiff accuses Defendants of falsely labeling their protein supplement products “Made in the U.S.A.,” although the products contain foreign ingredients. Complaint.
Sellers v. Kraft Heinz Foods Co., No. 0:16-cv-60624 (S.D. Fla.): Copycat putative class action asserting violations of Florida’s consumer protection statute, and raising claims of negligent misrepresentation, unjust enrichment and breach of express warranty. Plaintiff alleges that Defendant has falsely advertised its grated parmesan cheese products as containing “100% parmesan cheese,” when the products contain significant amounts of adulterants and fillers, including cellulose, a filler and anti-clumping agent derived from wood pulp. Complaint.
Lewis v. Kraft Heinz Foods Co., No. 1:16-cv-400 (E.D. Cal.): Copycat putative class action asserting violations of California’s CLRA, FAL, and UCL, and raising claims of fraud, negligent misrepresentation, unjust enrichment, and breach of warranty (express and implied merchantability). Plaintiff alleges that Defendant has falsely advertised its grated parmesan cheese products as containing “100% parmesan cheese,” when the products contain significant amounts of adulterants and fillers, including cellulose, a filler and anti-clumping agent derived from wood pulp. Complaint.
Saitta v. Target Corp., No. 1:16-cv-10586 (D. Ma.): Copycat putative national class action asserting claims of breach of warranty (express and implied merchantability) and unjust enrichment. Plaintiff alleges that Defendant has falsely advertised its grated parmesan cheese products as containing “100% parmesan cheese,” when the products contain significant amounts of adulterants and fillers, including cellulose, a filler and anti-clumping agent derived from wood pulp. Complaint.
Hackman v. Aldi Inc. dba Reggano, No. 2016CA002169B (D.C. Super. Ct.): Copycat putative class action asserting a violation of D.C.’s consumer protection statute and breach of warranty claims (express and implied merchantability). Plaintiff alleges that Defendant has falsely advertised its grated parmesan cheese products as containing “100% parmesan cheese,” when the products contain significant amounts of adulterants and fillers, including cellulose, a filler and anti-clumping agent derived from wood pulp. Complaint.
Hackman v. Wal-Mart Stores, Inc., No. 2016CA002170B (D.C. Super. Ct.): Copycat putative class action asserting a violation of D.C.’s consumer protection statute and breach of warranty claims (express and implied merchantability). Plaintiff alleges that Defendant has falsely advertised its grated parmesan cheese products as containing “100% parmesan cheese,” when the products contain significant amounts of adulterants and fillers, including cellulose, a filler and anti-clumping agent derived from wood pulp. Complaint.

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NOTICE: All slip opinions and orders are subject to formal revision and are superseded by the advance sheets and bound volumes of the Official Reports. If you find a typographical error or other formal error, please notify the Reporter of Decisions, Supreme Judicial Court, John Adams Courthouse, 1 Pemberton Square, Suite 2500, Boston, MA 02108-1750; (617) 5571030; SJCReporter@sjc.state.ma.us SJC-12221 PAUL CUCINELLI vs. COMMONWEALTH. Supreme Judicial Court, Superintendence of inferior courts. Practice, Criminal, Appellate Division, Sentence. May 3, 2017. Paul Cucinelli appeals from a judgment of the county court dismissing his petition for relief under G. L. c. 211, § 3, from a decision of the Appellate Division of the Superior Court increasing his sentence for armed robbery. 1 He has filed a memorandum pursuant to S.J.C. Rule 2:21, as amended, 434 Mass. 1301 (2001), which requires a party challenging an interlocutory ruling of the trial court to "set forth the reasons why review of the trial court decision cannot adequately be obtained on appeal from any final adverse judgment in the trial court or by other available means." 2 Rule 2:21 does not apply here, as the decision of the Appellate Division was not an interlocutory ruling. See Jones v. Commonwealth, 461 Mass. 1005, 1005 (2012). Nonetheless, it is evident on the record before us that relief was properly denied. Cucinelli argues that he has no right to appeal directly to the appellate courts from the Appellate 1 The petition was the second one filed by Cucinelli to challenge the same decision. In his first G. L. c. 211, § 3, petition, Cucinelli argued that he received ineffective assistance of counsel before the Appellate Division. A different single justice of this court denied relief, and Cucinelli did not appeal from that judgment. 2 Cucinelli has not filed an appendix as required by the rule, despite being granted an extension of time in which to do so. This presents a further reason not to disturb the decision of the single justice. 2 Division's decision. That is correct. G. L. c. 278, § 28B (decision of Appellate Division "shall be final"). That, however, does not mean that he is entitled to review under G. L. c. 211, § 3. "Rarely should we employ our superintendence power to review rulings in matters in which the Legislature has expressly stated that the decision of another court or judge 'shall be final.'" Commonwealth v. Barros, 460 Mass. 1015, 1015 (2011), quoting Hurley v. Superior Court Dep't of the Trial Court, 424 Mass. 1008, 1009 (1997). The single justice neither erred nor abused her discretion by denying relief. 3 Judgment affirmed. The case was submitted on the papers filed, accompanied by a memorandum of law. Paul Cucinelli, pro se. 3 To the extent that Cucinelli may be claiming that the new sentence ordered by the Appellate Division is illegal, he would have an adequate alternative means of obtaining review of his sentence. Under Mass. R. Crim. P. 30 (a), as appearing in 435 Mass. 1501 (2001), Cucinelli "may at any time, as of right, file a written motion requesting the trial judge to release him . . . or to correct the sentence then being served upon the ground that the confinement or restraint was imposed in violation of the Constitution or laws of the United States or of the Commonwealth of Massachusetts." If such a motion is denied, Cucinelli will have the right to appeal to the Appeals Court from the denial. Cucinelli offers no reason why this would not be an adequate alternative remedy.


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Boyd, L.A., Ridout, C., O’Sullivan, D.M. Leach, J.E. and H. Leung. 2012. Plant–pathogen interactions: disease resistance in modern agriculture. Trends in Genetics. 29(4):233-240.
Verdier, V., Triplett, L., Hummel, A.W., Corral, R., Cernadas, R.A., Schmidt, C.L., Bogdanove, A.J. and J.E. Leach. 2012. Transcription activator-like (TAL) effectors targeting OsSWEET genes enhance virulence on diverse rice (Oryza sativa) varieties when expressed individually in a TAL effector-deficient strain of Xanthomonas oryzae. New Phytologist 196(4):1197-1207.
Zhao, S., Poulin, L., Rodriguez, L.M., Serna, N.F., Liu, S-Y., Wonna, I., Szurek, B., Verdier, V., Leach, J.E., He, Y-Q., Feng, J-X. and R. Koebnik. 2012. Development of a variable number of tandem repeats typing scheme for the bacterial rice pathogen Xanthomonas oryzae pv. oryzicola. Phytopathology 102:948-956.
Hamilton, J.P., E.C. Neeno-Eckwall, B.N. Adhikari, N.T. Perna, N.Tisserat, J.E. Leach, C.A. Levesque and C.R. Buell. 2011. The Comprehensive Phytopathogen Genomics Resource: a web-based resource for data-mining plant pathogen genomes. Database Article ID bar053, doi:10.1093/database/bar053.
Verdier, V., C. Vera Cruz and J.E. Leach. 2011. Controlling rice bacterial blight in Africa: Needs and prospects. Journal of Biotechnology 159:320-328.
McKay, J.K. and J.E. Leach. 2011. Linkage illuminates a complex genome. Nature Biotechnology 29: 717-718.
Manosalva, P., M. Bruce and J.E. Leach. 2011. Rice 14-3-3 protein (GF14e) negatively affects cell death and disease resistance. Plant Journal 155(1):157-168.
Bogdanove A.J., R. Koebnik, H. Lu, A. Furutani, S.V. Angiuoli, P.B. Patil, M.A. Van Sluys, R.P. Ryan, D.F. Meyer, S.W. Han, G. Aparna, M. Rajaram, A.L. Delcher, A.M. Phillippy, D. Puiu, M.C. Schatz, M. Shumway, D.D. Sommer, C. Trapnell, F. Benahmed, G. Dimitrov, R. Madupu, D. Radune, S. Sullivan, G. Jha, H. Ishihara, S.W. Lee, A. Pandey, V. Sharma, M. Sriariyanun, B. Szurek, C.M. Vera-Cruz, K.S. Dorman, P.C. Ronald, V. Verdier, J.M. Dow, R.V. Sonti, S. Tsuge, V.P.Brendel, P.D. Rabinowicz, J.E. Leach, F.F. White and S.L. Salzberg. 2011. Two new complete genome sequences offer insight into host and tissue specificity of plant pathogenic Xanthomonasspp. Journal of Bacteriology 193(19):5450-5464.
Triplett, L. R., J. P. Hamilton, C. R. Buell, N. A. Tisserat, V. Verdier,F. Zink, and J. E. Leach. 2011. Genomic analysis of Xanthomonas oryzae isolates from rice grown in the United States reveals substantial divergence from known X. oryzae pathovars. Applied and Environmental Microbiology 77(12):3930-3937.
Gaines T.A., D.L. Shaner, S.M. Ward, J.E. Leach, C. Preston and P. Westra. 2011. Mechanism of resistance evolved glyophosate-resistant Palmer amaranth (Amaranthus palmeri). Journal of Agricultural and Food Chemistry 59(11):5886-5889.
Feuillet, C., J.E. Leach, J. Rogers, P.S. Schnable and K. Eversole. 2011. Crop genome sequencing: lessons and rationales. Trends in Plant Science 16(2):77-78.
Liu, Y., X.Y. Zhu, S. Zhang, M. Bernardo, J. Edwards, D.W. Galbraith, J.E. Leach, G. Zhang, B. Liu and H. Leung. 2011. Dissecting quantitative resistance against rice blast disease using hetergeneous inbred family lines in rice. Theoretical and Applied Genetics122(2):341-353.
Jahn, C.E., J.K. Mckay, R. Mauleon, J. Stephens, K.L. McNally, D.R. Bush, H. Leung and J.E. Leach. 2011. Genetic variation in biomass among 20 diverse rice varieties. Plant Physiology 155(1):157-168.
Heuberger A.L., M.R. Lewis, M.H. Chen, M.A. Brick, J.E. Leach and E.P. Ryan. 2010. Metabolomic and functional genomic analyses reveal varietal differences in bioactive compounds of cooked rice. PLos One 5 (9):e12915.
van Eck, L., T. Schultz, J.E. Leach, S.R. Scofield, F.B. Peairs, A.M. Botha and N.L.V. Lapitan. 2010. Virus induced gene silencing of WRKY53 and an inducible phenylalanine ammonia-lyase in wheat reduces aphid resistance. Plant Biotechnology Journal 8(9):1023-1032.
Gaines T.A., W. Zhang, D. Wang, B. Bukun, S.T. Chisholm, D.L. Shaner, S.J. Nissen, W.L. Patzoldt, P.J. Tranel, A.S. Culpepper, T.L. Grey, T.M. Webster, W.K. Vencill, R.D. Sammons R.D., J. Jiang, C. Preston, J.E. Leach and P. Westra. 2010. Gene amplification confers glyphosate resistance in Amaranthus palmeri. Proceedings of the National Academy of Sciences 107(3):1029-1034.
Webb, K.M., E. Garcia, C.M.V. Cruz and J.E. Leach. 2010. Influence of rice development on the function of bacterial blight resistance genes. European Journal of Plant Pathology 128(3):399-407.
Lang, J.M., J.P. Hamilton, M.G.Q. Diaz, M.A. Van Sluys, M.R.G Burgos, C.M.V. Cruz, C.R. Buell, N.A. Tisserat, J.E. Leach. 2010. Genomics-based diagnostic marker development for Xanthomonas pv. oryzae and X. oryzae pv. oryzicola. 2010. Plant Disease. 94(3):311-319.
Webb, K.M., I. Ona, J. Bai, K.A. Garrett, T. Mew, C.M.V Cruz and J.E. Leach. 2010. A benefit of high temperature: increased effectiveness of a rice bacterial blight disease resistance gene. New Phytologist 185(2):568-576.

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text:
TO THE SECRETARY OF THE NAVY: REFERENCE IS MADE TO A LETTER DATED JULY 5. TO HAVE BEEN MADE IN HIS BID ON WHICH CONTRACT NO. N60258S 9580 IS BASED. IT IS REPORTED THAT THE ACQUISITION COST OF THE MATERIAL COVERED BY ITEM 7 WAS ESTIMATED TO BE $1. SKAGGS WAS ACCEPTED AS TO THAT ITEM ON APRIL 22. IN WHICH HE STATED THAT HE WOULD NOT ACCEPT DELIVERY OF ITEM 7 UNLESS HE WAS PERMITTED TO CORRECT HIS BID PRICE ON THAT ITEM. SKAGGS ADVISED THE DISPOSAL OFFICER THAT HE HAD MADE AN ERROR IN HIS BID AND THAT HIS BID PRICE SHOULD HAVE READ $125 INSTEAD OF $250. SKAGGS WAS HIGHER THAN THE OTHER BIDS RECEIVED ON ITEM 7. IT DOES NOT APPEAR THAT THE DIFFERENCE WAS SO GREAT AS TO HAVE PLACED THE CONTRACTING OFFICER ON NOTICE OF THE PROBABILITY OF ERROR IN THE BID OF MR.
REFERENCE IS MADE TO A LETTER DATED JULY 5, 1960, WITH ENCLOSURES, FROM THE ASSISTANT CHIEF FOR PURCHASING, BUREAU OF SUPPLIES AND ACCOUNTS, REQUESTING A DECISION AS TO THE ACTION TO BE TAKEN CONCERNING AN ERROR ALLEGED BY PAUL A. SKAGGS, WIRE ROPE, GARDEN GROVE, CALIFORNIA, TO HAVE BEEN MADE IN HIS BID ON WHICH CONTRACT NO. N60258S 9580 IS BASED.
THE LONG BEACH NAVAL SHIPYARD, TORRANCE ANNEX, TORRANCE, CALIFORNIA, BY SITE SALES LETTER NO. SSL-25-60-60258 REQUESTED BIDS FOR THE PURCHASE FROM THE GOVERNMENT OF, AMONG OTHER ITEMS, ONE LOT CONSISTING OF SEVEN PALLETS OF MISCELLANEOUS WIRE ROPE WEIGHTING, INCLUDING THE REELS, APPROXIMATELY 4,800 POUNDS, ITEM 7. IT IS REPORTED THAT THE ACQUISITION COST OF THE MATERIAL COVERED BY ITEM 7 WAS ESTIMATED TO BE $1,700. IN RESPONSE MR. PAUL A. SKAGGS SUBMITTED A BID OFFERING TO PURCHASE ITEM 7 FOR THE SUM OF $250. THE BID OF MR. SKAGGS WAS ACCEPTED AS TO THAT ITEM ON APRIL 22, 1960.
BY LETTER DATED APRIL 28, 1960, IN WHICH HE STATED THAT HE WOULD NOT ACCEPT DELIVERY OF ITEM 7 UNLESS HE WAS PERMITTED TO CORRECT HIS BID PRICE ON THAT ITEM, MR. SKAGGS ADVISED THE DISPOSAL OFFICER THAT HE HAD MADE AN ERROR IN HIS BID AND THAT HIS BID PRICE SHOULD HAVE READ $125 INSTEAD OF $250. IN A LETTER DATED MAY 13, 1960, MR. SKAGGS STATED THAT HE INTENDED TO BID $50 PER TON ON THE 4,800 POUNDS (APPROXIMATELY 2 1/2 TONS) OF MATERIAL COVERED BY ITEM 7 AND THAT HE INSTRUCTED ONE OF HIS OFFICE GIRLS TO FILL OUT THE BID ACCORDINGLY, AND THAT SHE FAILED TO CONVERT THE 4,800 POUNDS TO A TONNAGE BASIS AND ERRONEOUSLY FILLED OUT THE BID ON THE BASIS OF A PRICE OF $50 PER 1,000 POUNDS.
THE LIST OF BIDS SHOWS THAT SEVEN OTHER BIDDERS ON ITEM 7 QUOTED PRICES RANGING FROM $157.99 TO $6. ALTHOUGH THE BID OF MR. SKAGGS WAS HIGHER THAN THE OTHER BIDS RECEIVED ON ITEM 7, IT DOES NOT APPEAR THAT THE DIFFERENCE WAS SO GREAT AS TO HAVE PLACED THE CONTRACTING OFFICER ON NOTICE OF THE PROBABILITY OF ERROR IN THE BID OF MR. SKAGGS. IN VIEW OF THE WIDE RANGE OF PRICES ORDINARILY RECEIVED ON WASTE, SALVAGE, AND SURPLUS PROPERTY, A MERE DIFFERENCE IN THE PRICES BID WOULD NOT NECESSARILY PLACE A CONTRACTING OFFICER ON NOTICE OF THE PROBABILITY OF ERROR IN A BID FOR THE PURCHASE OF SUCH PROPERTY FROM THE GOVERNMENT, AS WOULD A LIKE DIFFERENCE IN THE PRICES QUOTED ON NEW EQUIPMENT, SUPPLIES, ETC., TO BE FURNISHED TO THE GOVERNMENT. SEE UNITED STATES V. SABIN METAL CORPORATION, 151 F.SUPP. 683, CITING WITH APPROVAL 16 COMP. GEN. 596; 17 ID. 388; AND ID. 601. SEE, ALSO, 16 COMP. GEN. 976; 28 ID. 261; AND ID. 550. THE PRESENT RECORD INDICATES THAT THE ACCEPTANCE OF THE BID OF PAUL A. SKAGGS WAS IN GOOD FAITH, NO ERROR HAVING BEEN ALLEGED UNTIL AFTER AWARD. CONSEQUENTLY, IT MUST BE HELD THAT SUCH ACTION CONSUMMATED A VALID AND BINDING CONTRACT. SEE UNITED STATES V. PURCELL ENVELOPE COMPANY, 249 U.S. 313; AND AMERICAN SMELTING AND REFINING COMPANY V. UNITED STATES, 259 U.S. 75.
MOREOVER, THE RESPONSIBILITY FOR THE PREPARATION OF THE BID SUBMITTED WAS UPON THE BIDDER. SEE FRAZIER-DAVIS CONSTRUCTION CO. V. UNITED STATES, 100 C.CLS. 120, 163. IF, AS STATED IN HIS LETTER OF MAY 13, 1960, MR. SKAGGS INADVERTENTLY USED THE WRONG BASIS IN COMPUTING HIS BID PRICE, SUCH ERROR WAS DUE SOLELY TO HIS OWN NEGLIGENCE OR OVERSIGHT AND WAS IN NO WAY INDUCED OR CONTRIBUTED TO BY THE GOVERNMENT. ANY ERROR THAT WAS MADE IN THE BID OF MR. SKAGGS WAS UNILATERAL--- NOT MUTUAL--- AND, THEREFORE, DOES NOT ENTITLE MR. SKAGGS TO RELIEF FROM HIS OBLIGATION UNDER THE CONTRACT. SEE OGDEN AND DOUGHERTY V. UNITED STATES, 102 C.CLS. 249; AND SALIGMAN, ET AL V. UNITED STATES. 56 F.SUPP. 505, 507.

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12-1617f. Weeds, removal or destruction; assessment and collection of costs; notice; procedure. (a) The governing body of any city is hereby authorized to provide for and require the cutting or destruction of all weeds on lots or pieces of land within the city. Except as provided by subsection (b), the city clerk shall issue a notice to the owner, occupant or agent by certified mail, return receipt requested, or by personal service to cut or destroy such weeds. If the property is unoccupied and the owner is a nonresident, such notice shall be sent by certified mail, return receipt requested, to the last known address of the owner. The notice shall state that before the expiration of the waiting period provided herein the recipient thereof may request a hearing before the governing body or its designated representative. If the occupant, owner or agent fails to request a hearing or refuses to cut or remove such weeds, after five days' notice by the city clerk, or in cases where the owner is unknown or is a nonresident, and there is no resident agent, 10 days after notice has been published by the city clerk in the official city paper, the city shall cut or destroy such weeds and shall keep an account of the cost of same and report to the city clerk. Except as provided by subsection (b), the city shall give notice to the owner, occupant or agent by certified mail, return receipt requested, of the total cost of such cutting or removal incurred by the city. The city also may recover the cost of providing notice, including postage, required by this section. Such notice also shall state that payment of such cost is due and payable within 30 days following receipt of such notice. If the cost of such removal or abatement is not paid within the thirty-day period, the city may levy a special assessment for such cost against the lot or piece of land in the same manner as provided in K.S.A. 12-1617e, and amendments thereto, or the city may collect the cost in the manner provided by K.S.A. 12-1,115, and amendments thereto. The city may pursue collection both by levying a special assessment and in the manner provided by K.S.A. 12-1,115, and amendments thereto, but only until the full cost and any applicable interest has been paid in full.
(b) In lieu of giving notice as provided by subsection (a), a city may give notice as provided by this subsection. The governing body shall adopt an ordinance which states its weed removal policy and notification procedure. Such procedure shall provide for a minimum one-time yearly written notification by mail or personal service to the owner, occupant or agent. Such notice shall include the same information required by subsection (a). In addition, such notice shall include a statement that no further notice shall be given prior to removal of weeds.
History: L. 1915, ch. 144, § 1; L. 1917, ch. 112, § 1; R.S. 1923, § 12-1642; L. 1975, ch. 66, § 2; L. 1985, ch. 73, § 2; L. 1986, ch. 74, § 2; L. 1992, ch. 266, § 1; L. 1997, ch. 186, § 1; L. 1998, ch. 80, § 2; July 1.


Pursuant to The Hague Convention, Federal law prohibits the seizure, by force or violence, of any aircraft within the special aircraft jurisdiction of the United States, interference with flight crew members while aboard such aircraft, the carrying of concealed weapons or explosives aboard such aircraft, and the commission of certain crimes, including murder (18 U.S.C. § 1111), manslaughter (18 U.S.C. § 1112), maiming (18 U.S.C. § 114), sexual abuse (18 U.S.C. §§ 2241-43), assault (18 U.S.C. § 113) and robbery (18 U.S.C. § 2111), while aboard such aircraft. The Act also empowers the United States to prosecute aircraft piracy committed against a foreign civil aircraft which is outside the special aircraft jurisdiction of the United States if the foreign civil aircraft was in flight at the time of its hijacking and if the hijacker is subsequently found in the United States after the air piracy or, effective as of April 24, 1996, a national of the United States was aboard such aircraft or a national of the United States was a perpetrator of the offense. The aircraft piracy statute authorizes the Government to seek the death penalty if the death of another person results from the aircraft piracy. See JM 9-63.100, et seq. The definition of "special aircraft jurisdiction of the United States" is found at 49 U.S.C. § 46501(2). To be within the "special aircraft jurisdiction of the United States" the aircraft must be "in flight." Among the aircraft covered are all United States civilian and military aircraft (anywhere in the world as long as they are "in flight"), foreign aircraft within the territorial jurisdiction of the United States, and certain foreign civil aircraft that land in the United States after certain crimes have been committed aboard the aircraft while it was in flight outside of the United States.