METHOD FOR TIME SYNCHRONIZATION BETWEEN TWO COMPUTING DEVICES OF A DRIVER ASSISTANCE SYSTEM, DRIVER ASSISTANCE SYSTEM, AND MOTOR VEHICLE

A method for time synchronization between a first electronic computing device of a driver assistance system of a motor vehicle and at least a second electronic computing device of the driver assistance system is disclosed. The method includes: generating, by the first electronic computing device, an interrupt signal and a first timestamp of the first clock; sending the interrupt signal to the second electronic computing device; generating, by the second electronic computing device, a second timestamp of the second clock, depending on the received interrupt signal; determining the time difference based on a difference of the two timestamps; and performing time synchronization depending on the determined time difference.

USING PARALLEL DATA LINES FOR GPIO PURPOSES

A camera system for a vehicle that includes a camera unit having a serializer and a control unit having a deserializer connected to the serializer is provided. The deserializer includes a plurality of data contacts for parallel data output. One or more of the data contacts are data contact general purpose inputs/outputs (GPIO) pins that communicates with GPIO pins of a data processing unit of the control unit. 1. A camera system for a vehicle , comprising:a camera unit that includes a serializer; anda control unit that includes a deserializer connected to the serializer, the deserializer comprises a plurality of data contacts for parallel data output,', 'one or more of the data contacts communicate with General Purpose Input/Outputs (GPIO) pins of a data processing unit of the control unit,', 'the data contacts are used as GPIO pins for communication with the data processing unit of the control unit, and', 'control data is transmitted from the deserializer to another data processing unit of the control unit via the data contacts used as GPIO pins., 'wherein2. The camera system according to claim 1 , wherein the data processing unit of the control unit includes a system-on-chip and/or a micro control unit.3. The camera system according to claim 1 , wherein the control unit is of the low voltage differential signaling type.4. The camera system according to claim 1 , wherein claim 1 , beside the data contacts claim 1 , the deserializer includes first dedicated General Purpose Input/Outputs (GPIO) that communicate with respective second dedicated General Purpose Input/Outputs (GPIO) of the data processing unit of the control unit.5. The camera system according to claim 1 , wherein the data contacts are used as GPIO pins only deployable for output purposes.6. The camera system according to claim 1 , wherein a digital parallel video signal level of the serializer is configurable.7. The camera system according to claim 1 , wherein a pixel clock (PLCK) is used for data ...

Using parallel data lines for GPIO purposes

A camera system for a vehicle that includes a camera unit having a serializer and a control unit having a deserializer connected to the serializer is provided. The deserializer includes a plurality of data contacts for parallel data output. One or more of the data contacts are data contact general purpose inputs/outputs (GPIO) pins that communicates with GPIO pins of a data processing unit of the control unit.

FLUID SUITABLE FOR TREATMENT OF CARBONATE FORMATIONS CONTAINING A CHELATING AGENT

The present invention covers a fluid and kit of parts suitable for treating carbonate formations containing glutamic acid N,N-diacetic acid or a salt thereof (GLDA) and/or methylglycine N,N-diacetic acid or a salt thereof (MGDA), a corrosion inhibitor, and a surfactant, and the use thereof. 1. Fluid suitable for treating carbonate formations comprising glutamic acid N ,N-diacetic acid or a salt thereof (GLDA) and/or methylglycine N ,N-diacetic acid or a salt thereof (MGDA) , a corrosion inhibitor , and a surfactant.2. Fluid of claim 1 , wherein the amount of GLDA and/or MGDA is 5 to 30 wt % on the basis of the total weight of the fluid.3. Fluid of comprising GLDA.4. Fluid of claim 1 , wherein the corrosion inhibitor is present in an amount of 0.1-2 volume % on total fluid.5. Fluid of claim 1 , wherein the corrosion inhibitor is selected from the group consisting of amine compounds claim 1 , quaternary ammonium compounds claim 1 , and sulfur compounds.6. Fluid of claim 1 , wherein the surfactant is present in an amount of 0.1-2 volume % on total fluid.7. Fluid of claim 1 , wherein the surfactant is a nonionic or cationic surfactant.8. Fluid of claim 1 , wherein the surfactant is selected from the group consisting of quaternary ammonium compounds and derivatives thereof.9. Fluid of claim 1 , further comprising water as a solvent for the other components.10. Fluid of claim 1 , further comprising a biocide and/or a bactericide.11. Fluid of claim 1 , further comprising an additive selected from the group consisting of mutual solvents claim 1 , anti-sludge agents claim 1 , water-wetting or emulsifying surfactants claim 1 , corrosion inhibitor intensifiers claim 1 , foaming agents claim 1 , viscosifiers claim 1 , wetting agents claim 1 , diverting agents claim 1 , oxygen scavengers claim 1 , carrier fluids claim 1 , fluid loss additives claim 1 , friction reducers claim 1 , stabilizers claim 1 , rheology modifiers claim 1 , gelling agents claim 1 , scale inhibitors claim 1 ...

TREATMENT OF ILLITIC FORMATIONS USING A CHELATING AGENT

The present invention relates to a process for treating a sandstone formation comprising introducing a fluid containing glutamic acid N,N-diacetic acid or a salt thereof (GLDA) and/or methylglycine N,N-diacetic acid or a salt thereof (MGDA) and having a pH of between 1 and 14 into the formation. The invention in addition relates to a fluid suitable for use in the above process containing 5-30 wt % of glutamic acid N,N-diacetic acid or a salt thereof (GLDA) and/or methylglycine N,N-diacetic acid or a salt thereof (MGDA), a corrosion inhibitor, a surfactant, and a mutual solvent. 1. Process for treating an illite-containing formation comprising introducing a fluid comprising glutamic acid N ,N-diacetic acid or a salt thereof (GLDA) into the formation.2. Process for treating an illite-containing formation of claim 1 , wherein the formation is an illite-containing sandstone formation.3. Process of claim 1 , wherein the fluid contains between 5 and 30 wt % of GLDA on the basis of the total weight of the fluid.4. Process of claim 1 , wherein the pH is between 3.5 and 13.5. Process of claim 1 , wherein the temperature is between 77 and 400° F. (about 25 and 149° C.).6. Process of claim 1 , wherein the fluid comprises water as a solvent.7. Process of claim 1 , wherein the fluid a further comprises an additive selected from the group consisting of anti-sludge agents claim 1 , surfactants claim 1 , corrosion inhibitors claim 1 , mutual solvents claim 1 , corrosion inhibitor intensifiers claim 1 , foaming agents claim 1 , viscosifiers claim 1 , wetting agents claim 1 , diverting agents claim 1 , oxygen scavengers claim 1 , carrier fluids claim 1 , fluid loss additives claim 1 , friction reducers claim 1 , stabilizers claim 1 , rheology modifiers claim 1 , gelling agents claim 1 , scale inhibitors claim 1 , breakers claim 1 , salts claim 1 , brines claim 1 , pH control additives claim 1 , bactericides/biocides claim 1 , particulates claim 1 , crosslinkers claim 1 , salt ...

PROCESS AND FLUID TO IMPROVE THE PERMEABILITY OF SANDSTONE FORMATIONS USING A CHELATING AGENT

The present invention relates to a process for treating a sandstone formation comprising introducing a fluid containing glutamic acid N,N-diacetic acid or a salt thereof (GLDA) and having a pH of between 1 and 14 into the formation. The invention in addition relates to a fluid and a kit of parts suitable for use in the above process containing glutamic acid N,N-diacetic acid or a salt thereof (GLDA), a corrosion inhibitor, a surfactant, and optionally a mutual solvent. 1. Process for treating a sandstone formation comprising introducing a fluid containing glutamic acid N ,N-diacetic acid or a salt thereof (GLDA) and having a pH of between 1 and 14 into the formation.2. Process of claim 1 , wherein the temperature is between 35 and 400° F. (about 2 and 204° C.).3. Fluid suitable for use in the process of having a pH between 1 and 14 comprising 5-30 wt % on the basis of total fluid of glutamic acid N claim 1 ,N-diacetic acid or a salt thereof (GLDA) claim 1 , a corrosion inhibitor claim 1 , a surfactant claim 1 , and optionally a mutual solvent.4. Fluid of further comprising one or more components selected from the group consisting of anti-sludge agents claim 3 , water-wetting or emulsifying surfactants claim 3 , corrosion inhibitor intensifiers claim 3 , foaming agents claim 3 , viscosifiers claim 3 , wetting agents claim 3 , diverting agents claim 3 , oxygen scavengers claim 3 , carrier fluids claim 3 , fluid loss additives claim 3 , friction reducers claim 3 , stabilizers claim 3 , rheology modifiers claim 3 , gelling agents claim 3 , scale inhibitors claim 3 , breakers claim 3 , salts claim 3 , brines claim 3 , pH control additives claim 3 , bactericides/biocides claim 3 , particulates claim 3 , crosslinkers claim 3 , salt substitutes claim 3 , relative permeability modifiers claim 3 , sulfide scavengers claim 3 , fibres claim 3 , nanoparticles claim 3 , and consolidating agents.5. Fluid of claim 3 , wherein the surfactant is a nonionic or anionic surfactant.6. ...

PROCESS TO CONTROL IRON IN OIL AND GAS APPLICATIONS USING A CHELATING AGENT

The present invention relates to a process to control iron in a subterranean formation wherein a fluid containing glutamic acid N,N-diacetic acid or a salt thereof (GLDA) and/or methylglycine N,N-diacetic acid or a salt thereof (MGDA) is introduced into the formation at a temperature between 77 and 400° F. (about 2 and 204° C.). The invention also covers a process of treating a subterranean formation wherein simultaneously iron control takes place. 1. A process to control iron in subterranean formations wherein a fluid containing comprising glutamic acid N ,N-diacetic acid or a salt thereof (GLDA) and/or methylglycine N ,N-diacetic acid or a salt thereof (MGDA) is introduced into the formation at a temperature between 77 and 400° F. (about 25 and 204° C.) , wherein simultaneously the subterranean formation is treated by introducing the fluid into the formation.2. (canceled)3. Process of claim 1 , wherein the temperature is between 77 and 300° F. (about 25 and 149° C.).4. Process of claim 1 , wherein the amount of GLDA and/or MGDA in the fluid is between 0.1 and 30 wt % on the basis of total weight of the fluid.5. Process of claim 1 , wherein the fluid comprises GLDA.6. Process of claim 1 , wherein the fluid further comprises another inorganic acid claim 1 , HCl claim 1 , HF claim 1 , an organic acid claim 1 , citric acid claim 1 , formic acid or acetic acid.7. Process of claim 1 , wherein the fluid further comprises a corrosion inhibitor.8. Process of claim 1 , wherein the fluid further comprises a biocide and/or bactericide.9. Process of claim 1 , wherein the fluid further comprises one or more additives selected from the group consisting of mutual solvents claim 1 , anti-sludge agents claim 1 , water-wetting or emulsifying surfactants claim 1 , corrosion inhibitor intensifiers claim 1 , foaming agents claim 1 , viscosifiers claim 1 , wetting agents claim 1 , diverting agents claim 1 , oxygen scavengers claim 1 , carrier fluids claim 1 , fluid loss additives claim ...

AMMONIUM SALTS OF CHELATING AGENTS AND THEIR USE IN OIL AND GAS FIELD APPLICATIONS

The present invention relates to a process for treating a subterranean formation wherein a fluid containing an ammonium salt of glutamic acid N, N-diacetic acid (GLDA) or methylglycine N, N-diacetic acid (MGDA) is introduced into the formation. The invention also covers a fluid containing an ammonium salt of GLDA and/or MGDA and at least one component from the group of seawater, mutual solvents, anti-sludge agents, (water-wetting or emulsifying) surfactants, foaming agents, corrosion inhibitors corrosion inhibitor intensifiers, viscosifiers, wetting agents, diverting agents, oxygen scavengers, carrier fluids, fluid loss additives, friction reducers, stabilizers, rheology modifiers, gelling agents, scale inhibitors, breakers, salts, brines, pH control additives, bactericides/biocides, particulates, crosslinkers, salt substitutes (such as tetramethyl ammonium chloride), relative permeability modifiers, sulfide scavengers, fibres, nanoparticles, and consolidating agents, and covers an ammonium salt of the formula M(NH),H-GLDA or the formula M(NH),H-MGDA, wherein M is an alkalimetal cation, x is at least 0.1, y is at least 0.1 and x+y+z=4 for GLDA and x+y+z=3 for MGDA. 1. Process for treating a subterranean formation wherein a fluid comprising an ammonium salt of glutamic acid N ,N-diacetic acid (GLDA) and/or methylglycine N ,N-diacetic acid (MGDA) is introduced into the formation.2. Process of claim 1 , wherein the fluid contains 5 to 50 wt % of an ammonium salt of GLDA and/or MGDA on the basis of the total weight of the fluid.3. Process of claim 1 , wherein the fluid comprises an ammonium GLDA.4. Process of claim 1 , wherein the subterranean formation is a carbonate or sandstone-containing formation.5. Process of claim 1 , wherein the subterranean formation is accessed through seawater.6. Process of claim 1 , wherein the temperature is between 77 and 400° F. (about 25 and 204° C.).7. Fluid comprising an ammonium salt of glutamic acid N claim 1 ,N-diacetic acid (GLDA) ...

ENHANCED OIL RECOVERY USING SEAWATER AND EDTA

The enhanced oil recovery using seawater and EDTA (ethylenediaminetetraacetic acid) is a method that uses injection of EDTA in seawater to enhance the recovery of oil from sandstone reservoirs. The EDTA may be introduced into seawater during the initial extraction of oil from the reservoir by seawater injection, or a solution of EDTA in seawater may be used to flush residual oil from the reservoir after the initial extraction by seawater injection. In either case, the EDTA is present in about 1.0 wt % to about 5.0 wt % of the seawater solution, and the solution has a pH of between 10.5 and 11.0. 1. A method for enhanced oil recovery from a sandstone oil reservoir , comprising the step of injecting a solution consisting of an effective amount of ethylenediaminetetraacetic acid (EDTA) in seawater into the reservoir for chelating cations in the formation brine to prevent scaling caused by mixing the seawater with the formation brine.2. The method for enhanced oil recovery according to claim 1 , wherein the effective amount of EDTA comprises about 1 wt % EDTA.3. The method for enhanced oil recovery according to claim 1 , wherein the effective amount of EDTA comprises about 5 wt % EDTA.4. The method for enhanced oil recovery according to claim 1 , wherein the solution has a pH of about 11.5. The method for enhanced oil recovery according to claim 1 , wherein the step of injecting the solution comprises injecting the solution for the initial recovery of oil from the reservoir.6. The method for enhanced oil recovery according to claim 1 , wherein the step of injecting the solution comprises injecting the solution containing the EDTA after the initial recovery of oil from the reservoir by seawater flooding in order to recover residual oil from the reservoir.7. A method for enhanced oil recovery from a sandstone oil reservoir claim 1 , comprising the step of injecting a solution consisting of between 1 wt % and 5 wt % ethylenediaminetetraacetic acid (EDTA) in seawater into ...

CHELATING FLUID FOR ENHANCED OILRECOVERY IN CARBONATE RESERVOIRS AND METHOD OF USING THE SAME

The chelating fluid for enhanced oil recovery in carbonate reservoirs and the method of using the same utilizes a chelating fluid injected into a carbonate oil reservoir through a fluid injection system. The chelating fluid is a solution of a polyamino carboxylic acid chelating agent in brine, with the polyamino carboxylic acid chelating agent having a concentration of approximately 5.0 wt % of the solution, with the solution having a pH of approximately 11.0. The polyamino carboxylic acid chelating agent is preferably ethylenediaminetetraacetic acid (EDTA). The brine preferably has a relatively high salinity, with a sodium chloride concentration preferably on the order of approximately 18,300 ppm. 1. A chelating fluid for enhanced oil recovery in carbonate reservoirs , comprising a solution of a polyamino carboxylic acid chelating agent in brine , wherein the polyamino carboxylic acid chelating agent comprises approximately 5.0 wt % of the solution , the solution having a pH of approximately 11.0.2. The chelating fluid for enhanced oil recovery in carbonate reservoirs as recited in claim 1 , wherein the polyamino carboxylic acid chelating agent comprises ethylenediaminetetraacetic acid.3. The chelating fluid for enhanced oil recovery in carbonate reservoirs as recited in claim 1 , wherein the brine has a sodium chloride concentration of approximately 18 claim 1 ,300 ppm.4. A method of preventing scale formation in water injection systems of carbonate oil reservoirs claim 1 , comprising the step of injecting a chelating fluid into an oil reservoir through a fluid injection system claim 1 , wherein the chelating fluid comprises a polyamino carboxylic acid chelating agent forming approximately 5.0 wt % of the chelating fluid claim 1 , the chelating fluid having a pH of approximately 11.0.5. The method of preventing scale formation in water injection systems of carbonate oil reservoirs as recited in claim 4 , wherein the polyamino carboxylic acid chelating agent ...

Ridge gap waveguide switches and reconfigurable power splitters

Ridge Gap Waveguide (RGW) has emerged as a preferred waveguide technology for millimeter-wave frequencies. Microwave power splitters and switches represent important components for routing microwave signals and/or splitting a microwave signal into equal or unequal portions. To date, solutions have typically employed MEMS phase shifters, MEMS reflective loads, etc. or monolithic microwave integrated circuits to replace traditional electromechanical switches. However, such devices have typically demonstrated at frequencies below 18 GHz and require transitions to/from the RGW. The inventors have established an alternate design, which provides a reconfigurable power splitter and/or microwave switch, which is directly within the same metallic RGW waveguide technology. Such RGW power splitters and switches operating at higher frequencies, such as 26 GHz-40 GHz, for example.

ORGANIC ACID FRACTURING FLUID COMPOSITION

A fracturing fluid composition that includes a chelating agent, e.g. GLDA, and a polymeric additive comprising a copolymer of acrylamido-tert-butyl sulfonate and hydrolyzed polyacrylamide diluted in an aqueous base fluid, e.g. seawater, and a method of fracking a geological formation using the fracturing fluid composition. Various embodiments of the fracturing fluid composition and the method of fracking are also provided. 1: An organic acid fracturing fluid composition , comprising:an aqueous base fluid;a chelating agent comprising glutamic diacetic acid in an amount of 5-20 wt %, wherein wt % is relative to the total weight of the fracturing fluid composition; anda polymeric additive comprising a copolymer of acrylamido-tert-butyl sulfonate and partially hydrolyzed polyacrylamide, in an amount of 0.45-1 wt %, wherein wt % is relative to the total weight of the fracturing fluid composition, wherein the polymeric additive is present in the fracturing fluid composition at a concentration of no more than 1 wt % relative to the total weight of the fracturing fluid composition;wherein a weight percent of acrylamido-tert-butyl sulfonate in the copolymer is in the range of 5 to 20 wt %, and a weight percent of the partially hydrolyzed polyacrylamide in the copolymer is in the range of 80 to 95 wt %, each relative to the total weight of the copolymer.24-: (canceled)5: The fracturing fluid composition of claim 1 , wherein the aqueous base fluid is seawater.67-. (canceled)8: The fracturing fluid composition of claim 1 , which does not include claim 1 , other than the chelating agent and the polymeric additive claim 1 , additional additives selected from the group consisting of an antiscalant claim 1 , a deflocculant claim 1 , a crosslinker claim 1 , a breaker claim 1 , a fluid loss additive claim 1 , a buffer claim 1 , an interfacial tension reducer claim 1 , and a biocide.9: The fracturing fluid composition of claim 1 , which has a plastic viscosity of 2 to 8 cP at a ...

TREATMENT OF SHALE FORMATONS USING A CHELATING AGENT

The present invention relates to a process for treating a shale formation comprising introducing a fluid containing glutamic acid N,N-diacetic acid or a salt thereof (GLDA), methylglycine N,N-diacetic acid or a salt thereof (MGDA),and/or N- hydroxyethyl ethylenediamine N,N′,N′-triacetic acid or a salt thereof (HEDTA) into the formation which process may optionally contain an additional fracturing step. 1. A process for treating a shale formation comprising introducing a fluid containing glutamic acid N ,N-diacetic acid or a salt thereof (GLDA) , methylglycine N ,N-diacetic acid or a salt thereof (MGDA) , and/or N-hydroxyethyl ethylenediamine N ,N′ ,N′-triacetic acid or a salt thereof (HEDTA) into the formation.2. The process for treating a shale formation of comprising an additional step of fracturing the shale formation wherein the fracturing step can take place before introducing the fluid into the formation claim 1 , while introducing the fluid into the formation or subsequent to introducing the fluid into the formation3. The process of claim 2 , wherein the fluid containing glutamic acid N claim 2 ,N-diacetic acid or a salt thereof (GLDA) claim 2 , methylglycine N claim 2 ,N-diacetic acid or a salt thereof (MGDA) claim 2 , and/or N-hydroxyethyl ethylenediamine N claim 2 ,N′ claim 2 ,N′-triacetic acid or a salt thereof (HEDTA) is also the fracturing fluid in the fracturing step.4. The process of claim 1 , wherein the fluid contains between 3 and 30 wt % of GLDA claim 1 , MGDA claim 1 , and/or HEDTA based on the total weight of the fluid.5. The process of claim 1 , wherein the fluid contains GLDA.6. The process of claim 1 , wherein the fluid has a pH of between 3 and 13.7. The process of claim 6 , wherein the pH is between 3 and 6.8. The process of claim 1 , wherein the process is done at a temperature of between 77 and 300° F. (about 25 and 149° C.).9. The process of claim 1 , wherein the fluid contains water as a solvent.10. The process of claim 1 , wherein the ...

PROCESS TO FRACTURE A SUBTERRANEAN FORMATION USING A CHELATING AGENT

The present invention relates to a process for fracturing a subterranean formation comprising a step of fracturing the formation and a step of introducing a treatment fluid containing glutamic acid N,N-diacetic acid or a salt thereof (GLDA), methylglycine N,N-diacetic acid or a salt thereof (MGDA) and/or N-hydroxyethyl ethylenediamine N,N′,N′-triacetic acid or a salt thereof (HEDTA) into the formation, wherein the fracturing step can take place before introducing the treatment fluid into the formation, while introducing the treatment fluid into the formation or subsequent to introducing the treatment fluid into the formation. 1. A process for fracturing a subterranean formation comprising a step of fracturing the formation and a step of introducing a treatment fluid containing glutamic acid N ,N-diacetic acid or a salt thereof (GLDA) , methylglycine N ,N-diacetic acid or a salt thereof (MGDA) and/or N-hydroxyethyl ethylenediamine N ,N′ ,N′-triacetic acid or a salt thereof (HEDTA) into the formation , wherein the fracturing step can take place before introducing the treatment fluid into the formation , while introducing the treatment fluid into the formation or subsequent to introducing the treatment fluid into the formation , the treatment fluid is allowed to contact the surfaces of the subterranean formation in the fractured zones , to change at least part of these surfaces , to create an inhomogeneous fracture surface , to remove small particles and fines from the fractures , and/or to prevent the fractures from completely closing immediately when the fracture pressure is released to achieve at least one of (i) an increased permeability or conductivity , (ii) the removal of small particles , and (iii) the removal of inorganic scale , and so ultimately enhance the well performance and enable an increased production of oil and/or gas from the fractured formation , and the treatment fluid contains between 5 and 30 wt % of GLDA , MGDA and/or HEDTA based on the total ...

ACINETOBACTER O-OLIGOSACCHARYLTRANSFERASES AND USES THEREOF

The present application provides methods and uses of O-oligosaccharyltransferase (O-OTases) for generating vaccines. In particular, the present application provides a method of synthesizing a glycoprotein comprising glycosylation of pilin-like protein ComP using a Pg1LO-OTase. Uses of glycoproteins synthesized by glycosylating ComP using Pg1LO-OTase, particularly for the preparation of vaccines and the like, including a vaccine to , is also provided. 1. A method of synthesizing a glycoprotein comprising glycosylation of ComP using a PglLO-oligosaccharyltransferase.2. The method of claim 1 , wherein the ComP is optionally fused to a second protein claim 1 , an adjuvant or a carrier.3. The method of or claim 1 , which is performed in Gram negative bacteria.4AcinetobacterE. coli.. The method of claim 3 , wherein the bacteria is or5. The method of any one of to claim 3 , wherein the glycosylation uses sugars derived from O-glycosylation claim 3 , N-glycan claim 3 , O-antigens claim 3 , or a capsular polysaccharide.6Streptococcus. The method of claim 5 , wherein the capsular polysaccharide is a capsule.7StreptococcusStreptococcus pneumoniae.. The method of claim 6 , wherein the is8Campylobacter.. The method of claim 5 , wherein the N-glycan is derived from9Campylobacter jejuni. The method of claim 8 , wherein the N-glycan is a N-heptasaccharide.10AcinetobacterA. baylyi, A. baumannii, A. nosocomialisA. calcoaceticus.. The method of claim 4 , wherein the is claim 4 , or11. An O-oligosaccharyltransferase for glycosylation of ComP.12. The O-oligosaccharyltransferase of claim 11 , wherein the glycosylation is recombinantly produced in Gram negative bacteria.13AcinetobacterE. coli.. The O-oligosaccharyltransferase of claim 12 , wherein the bacteria is or14. The O-oligosaccharyltransferase of any one of to claim 12 , wherein the glycosylation uses sugars derived from O-glycosylation claim 12 , N-glycan claim 12 , O-antigens claim 12 , or capsular polysaccharide.15Streptococcus ...

FRACTURING FLUID COMPOSITION CONTAINING AN ACRYLAMIDO-TERT-BUTYLSULFONATE POLYMER

A fracturing fluid composition that includes a chelating agent, e.g. GLDA, and a polymeric additive comprising a copolymer of acrylamido-tert-butyl sulfonate and hydrolyzed polyacrylamide diluted in an aqueous base fluid, e.g. seawater, and a method of fracking a geological formation using the fracturing fluid composition. Various embodiments of the fracturing fluid composition and the method of fracking are also provided. 1: A fracturing fluid composition , comprising:an aqueous base fluid;a chelating agent comprising glutamic diacetic acid in an amount of 5-20 wt %, wherein wt % is relative to the total weight of the fracturing fluid composition; anda polymeric additive comprising a copolymer of acrylamido-tert-butyl sulfonate and partially hydrolyzed polyacrylamide, in an amount of 0.45-1 wt %, wherein wt % is relative to the total weight of the fracturing fluid composition, wherein the partially hydrolyzed polyacrylamide has a molar ratio of amide groups to carboxylate groups of 0.5 to 6;wherein a weight percent of acrylamido-tert-butyl sulfonate in the copolymer is in the range of 5 to 20 wt %, and a weight percent of the partially hydrolyzed polyacrylamide in the copolymer is in the range of 80 to 95 wt %, each relative to the total weight of the copolymer.24-. (canceled)5: The fracturing fluid composition of claim 1 , wherein the aqueous base fluid is seawater.68-. (canceled)9: The fracturing fluid composition of claim 1 , which has a plastic viscosity of 2 to 8 cP at a temperature of 280 to 320° F.10: The fracturing fluid composition of claim 1 , which has a yield point of 2 to 15 lb/100 ftat a temperature of 280 to 320° F.1120-. (canceled)21: The fracturing fluid composition of claim 1 , wherein a weight percent of acrylamido-tert-butyl sulfonate in the copolymer is in the range of 5 to 10 wt % claim 1 , and a weight percent of partially hydrolyzed polyacrylamide in the copolymer is in the range of 90 to 95 wt % claim 1 , each relative to the total weight ...

METHODS FOR REDUCING CONDENSATION

A method for reducing condensate in a subsurface formation is disclosed. The method comprises introducing a first reactant and a second reactant into the subsurface formation. The first reactant and the second reactant produce an exothermic reaction that increases temperature and pressure in the subsurface formation to greater than a dew point of the condensate. Increasing the temperature and pressure in the subsurface formation to greater than the dew point of the condensate vaporizes, and thereby reduces, condensate in the subsurface formation. 1. A method for reducing condensate in a subsurface formation , the method comprising: 'the first reactant and the second reactant produce an exothermic reaction that increases temperature and pressure in the subsurface formation to greater than a dew point of the condensate, wherein increasing the temperature and pressure in the subsurface formation to greater than the dew point of the condensate vaporizes and thereby reduces condensate in the subsurface formation.', 'introducing a first reactant and a second reactant into the subsurface formation, wherein'}2. The method of claim 1 , in which introducing the first reactant and the second reactant into the subsurface formation comprises introducing each reactant into the subsurface formation separately.3. The method of claim 2 , in which introducing the first reactant and the second reactant into the subsurface formation comprises introducing the first reactant into the subsurface formation through coiled tubing and introducing the second reactant into the subsurface formation through an annulus of a wellbore.4. The method of claim 1 , in which introducing the first reactant and the second reactant into the subsurface formation comprises introducing a mixture comprising the first reactant and the second reactant into the subsurface formation.5. The method of claim 4 , in which the method further comprises introducing a buffer solution with the first and second reactants ...

Method of drilling a subterranean geological formation with a drilling fluid composition comprising copper nitrate

A drilling fluid composition comprising an aqueous base fluid, a viscosifier, and a H 2 S scavenger comprising copper nitrate, wherein the drilling fluid composition has a H 2 S sorption capacity from about 4.0 to about 6.0 gram per one milliliter of the drilling fluid composition; and a method of drilling a subterranean geological formation using thereof are provided. Various embodiments of the drilling fluid composition and the method are also provided.

Voltage regulator module with cooling structure

A high-power Voltage Regulator Module (VRM) includes a housing having side walls, an upper opening, and a lower opening, a VRM circuit board oriented within the housing, a plane of the VRM circuit board oriented in parallel to at least one of the side walls of the housing, an upper Printed Circuit Board (PCB) coupled to the upper opening of the housing, a lower panel coupled to the lower opening of the housing, a coolant inlet port formed in the lower panel, and a coolant outlet port formed in the lower panel. The high power VRM may include a coolant inlet adapter coupled to the coolant inlet port and a coolant outlet adapter coupled to the coolant outlet port. The coolant inlet adapter and the coolant outlet adapter may provide support for the VRM.

HEAVY OIL AS FRACTURING FLUID TO INCREASE HYDRAULIC FRACTURING EFFICIENCY

Compositions, systems, and methods for hydraulically fracturing a hydrocarbon-bearing formation, a method including injecting into the hydrocarbon-bearing formation under increased pressure a heavy oil fracturing fluid; allowing the heavy oil fracturing fluid to remain in situ for a period of time suitable to create fractures in the hydrocarbon-bearing reservoir, the heavy oil fracturing fluid operable to undergo an at least about 70% viscosity decrease in situ; and flowing back the heavy oil fracturing fluid to the surface without damaging the hydrocarbon-bearing formation or reducing production of hydrocarbons from the hydrocarbon-bearing formation. 1. A method for hydraulically fracturing a hydrocarbon-bearing formation , the method comprising the steps of:injecting into the hydrocarbon-bearing formation under increased pressure a heavy oil fracturing fluid;allowing the heavy oil fracturing fluid to remain in situ for a period of time suitable to create fractures in the hydrocarbon-bearing reservoir, the heavy oil fracturing fluid operable to undergo an at least about 70% viscosity decrease in situ; andflowing back the heavy oil fracturing fluid to the surface without damaging the hydrocarbon-bearing formation or reducing production of hydrocarbons from the hydrocarbon-bearing formation.2. The method according to claim 1 , where the heavy oil fracturing fluid is operable to undergo an at least about 90% viscosity decrease in situ.3. The method according to claim 1 , where the at least about 70% viscosity decrease in situ allows for an at least about 30% reduction in breakdown pressure of a rock matrix in the hydrocarbon-bearing formation versus breakdown pressure applying a fracturing fluid at viscosity conditions of the heavy oil fracturing fluid at surface conditions.4. The method according to claim 2 , where the at least about 90% viscosity decrease in situ allows for an at least about 40% reduction in breakdown pressure of a rock matrix in the hydrocarbon- ...

Method of producing sodium bentonite

Method of converting calcium bentonite to sodium bentonite that is suitable for use as drilling mud or a cement additive. After the addition of a calcium bentonite sample to a prepared soda ash solution at predetermined soda ash/bentonite weight ratios, the bentonite suspension is continuously heated and stirred for up to 24 h. The heating and stirring are crucial towards enhancing the sodium activation of the bentonite, as well as other rheological properties of the bentonite.

Acinetobacter O-Oligosaccharyltransferases and Uses Thereof

The present application provides methods and uses of O-oligosaccharyltransferase (O-OTases) for generating vaccines. In particular, the present application provides a method of synthesizing a glycoprotein comprising glycosylation of pilin-like protein ComP using a Pg1LO-OTase. Uses of glycoproteins synthesized by glycosylating ComP using Pg1LO-OTase, particularly for the preparation of vaccines and the like, including a vaccine to is also provided. 126-. (canceled)27. A bacterial cell expressing a Pg1LcomP O-oligosacharyltransferase , a fusion protein comprising ComP , and a polysaccharide containing glucose at its reducing end.28. The bacterial cell of wherein the cell also comprises the ComP fusion protein glycosylated with the polysaccharide.29AcinetobacterE. coli.. The bacterial cell of claim 27 , wherein the bacterial cell is or30A. baylyi, A. baumannii, A. nosocomialis,A. calcoaceticus.. The bacterial cell of claim 29 , wherein the Acinetobacter is or31E. coli.. The bacterial cell of claim 29 , wherein the bacterial cell is32. The bacterial cell of claim 27 , wherein the polysaccharide is a bacterial capsular polysaccharide.33Streptococcus. The bacterial cell of claim 32 , wherein the capsular polysaccharide is a capsule.34Streptococcus pneumoniae. The bacterial cell of claim 32 , wherein the capsular polysaccharide is a capsule.35AcinetobacterE. coli.. The bacterial cell of claim 28 , wherein the bacterial cell is or36AcinetobacterA. baylyi, A. baumannii, A. nosocomialis,A. calcoaceticus.. The bacterial cell of claim 35 , wherein the is or37E. coli.. The bacterial cell of claim 35 , wherein the bacterial cell is38. The bacterial cell of claim 28 , wherein the polysaccharide is a bacterial capsular polysaccharide.39Streptococcus. The bacterial cell of claim 38 , wherein the capsular polysaccharide is a capsule.40Streptococcus pneumoniae. The bacterial cell of claim 38 , wherein the capsular polysaccharide is a capsule.41. A bacterial cell comprising a ...

METHOD FOR DETERMINING ACIDIZATION EFFECTIVENESS FOR WELLBORE OPERATIONS

A method of acidizing a geological formation is provided. A method of determining an effectiveness of the acidizing with NMR spectroscopy is also provided. Various embodiments of the method of acidizing and the method of determining the effectiveness of the acidizing are specified. 116-. (canceled)17. A method of determining an effectiveness of acidizing a geological formation , the method comprising:recording a first nuclear magnetic resonance (NMR) spectrum of the geological formation over a micro-pore relaxation range, a meso-pore relaxation range, and a macro-pore relaxation range;calculating a first interconnectivity number by dividing a first micro-meso interconnectivity number to a first meso-macro interconnectivity number, wherein the first micro-meso interconnectivity number is a ratio of an intensity of the first NMR spectrum at a micro-meso diffusional coupling to a peak intensity of the first NMR spectrum in the micro-pore relaxation range or the meso-pore relaxation range, and the first meso-macro interconnectivity number is a ratio of an intensity of the first NMR spectrum at a meso-macro diffusional coupling to a peak intensity of the first NMR spectrum in the meso-pore relaxation range or the macro-pore relaxation range;acidizing the geological formation by delivering a stimulation fluid to the wellbore, thereby forming an acidized geological formation, wherein the acidizing includes injecting the stimulation fluid into the geological formation at a pressure of no more than 5,000 psi;recording a second NMR spectrum of the acidized geological formation over the micro-pore relaxation range, the meso-pore relaxation range, and the macro-pore relaxation range;calculating a second interconnectivity number by dividing a second micro-meso interconnectivity number to a second meso-macro interconnectivity number, wherein the second micro-meso interconnectivity number is a ratio of an intensity of the second NMR spectrum at a micro-meso diffusional coupling to ...

STIMULATION FLUID INJECTION METHOD AND NMR VERIFICATION

A method of acidizing a geological formation is provided. A method of determining an effectiveness of the acidizing with NMR spectroscopy is also provided. Various embodiments of the method of acidizing and the method of determining the effectiveness of the acidizing are specified. 1. A method of acidizing a geological formation surrounding a wellbore , comprising:recording a first nuclear magnetic resonance (NMR) spectrum of a portion of the geological formation over a micro-pore relaxation range, a meso-pore relaxation range, and a macro-pore relaxation range;calculating a first interconnectivity number by dividing a first micro-meso interconnectivity number to a first meso-macro interconnectivity number, wherein the first micro-meso interconnectivity number is a ratio of an intensity of the first NMR spectrum at a micro-meso diffusional coupling to a peak intensity of the first NMR spectrum in the micro-pore relaxation range or the meso-pore relaxation range, and the first meso-macro interconnectivity number is a ratio of an intensity of the first NMR spectrum at a meso-macro diffusional coupling to a peak intensity of the first NMR spectrum in the meso-pore relaxation range or the macro-pore relaxation range;acidizing the geological formation by delivering a first stimulation fluid to the portion of the geological formation, thereby forming an acidized geological formation, wherein the acidizing includes injecting the first stimulation fluid into the geological formation at a pressure of no more than 5,000 psi;recording a second NMR spectrum of the acidized geological formation over the micro-pore relaxation range, the meso-pore relaxation range, and the macro-pore relaxation range;calculating a second interconnectivity number by dividing a second micro-meso interconnectivity number to a second meso-macro interconnectivity number, wherein the second micro-meso interconnectivity number is a ratio of an intensity of the second NMR spectrum at a micro-meso ...

Method for drilling a hydrogen sulfide-containing formation

A drilling fluid composition comprising an aqueous base fluid, a viscosifier, and a H2S scavenger comprising copper nitrate, wherein the drilling fluid composition has a H2S sorption capacity from about 4.0 to about 6.0 gram per one milliliter of the drilling fluid composition; and a method of drilling a subterranean geological formation using thereof are provided. Various embodiments of the drilling fluid composition and the method are also provided.

METHOD FOR DRILLING A WELLBORE WITH A WEIGHTED HYDROGEN SULFIDE SCAVENGER FLUID

A drilling fluid composition comprising an aqueous base fluid, a viscosifier, and a HS scavenger comprising copper nitrate, wherein the drilling fluid composition has a HS sorption capacity from about 4.0 to about 6.0 gram per one milliliter of the drilling fluid composition; and a method of drilling a subterranean geological formation using thereof are provided. Various embodiments of the drilling fluid composition and the method are also provided. 1: A method of drilling a wellbore with a weighted HS scavenger fluid , comprising:{'sub': '2', 'driving a drill bit to form the wellbore into a subterranean geological formation thereby producing a formation fluid that contains HS; and'} [ an aqueous base fluid,', 'a weighting agent in an amount of from 5 wt % to 15 wt % based on the total weight of the drilling fluid composition,', 'a viscosifier in an amount of from 0.5 to 5.0 wt %, based on the total weight of the drilling fluid composition, and', {'sub': '2', 'a HS scavenger consisting of copper nitrate, and'}], 'wherein the drilling fluid composition comprises'}, {'sub': '2', 'wherein copper nitrate present in the drilling fluid composition reacts with HS present in the formation fluid to form copper sulfide;'}], 'injecting a drilling fluid composition into the subterranean geological formation through the wellbore,'}recovering the copper sulfide from the drilling fluid composition; andtreating the copper sulfide with nitric acid to regenerate copper nitrate while concurrently forming elemental sulfur.2: The method of claim 1 , wherein the wellbore is a horizontal or a multilateral wellbore.3: The method of claim 1 , wherein a temperature of the wellbore ranges from 50 to 200° C.4: The method of claim 1 ,{'sub': '2', 'wherein the wellbore contains a casing that is made of at least one metal selected from the group consisting of stainless steel, aluminum, and titanium, the casing is exposed to a gaseous mixture containing up to 12 vol % of HS, and'}{'sup': '2', ' ...

METHOD FOR ENHANCED OIL RECOVERY BY IN SITU CARBON DIOXIDE GENERATION

The method for enhanced oil recovery by in situ carbon dioxide generation utilizes a chelating fluid injected into an oil reservoir through a fluid injection system. The chelating fluid is a low pH solution of a polyamino carboxylic acid chelating agent. The polyamino carboxylic acid chelating agent may have a concentration of about 5 wt %. The polyamino carboxylic acid chelating agent is preferably either an aqueous solution of HNa-ethylenediaminetetraacetic acid (pH 4.5), H-hydroxyethyl ethylenediamine triacetic acid (pH 2.5), or an aqueous solution of HNaHEDTA (pH 4). The injection of the chelating fluid may be preceded by flooding the core with seawater, and is followed by injection of either to seawater, a high pH chelating agent, or low salinity water to ensure maximal extraction of oil from the reservoir. The method is particularly for use in formations where the core of the reservoir has a carbonate rock matrix. 1. A method for enhanced oil recovery from a carbonate reservoir , comprising the steps of:injecting an aqueous solution of a low pH polyamino carboxylic acid chelating agent into the core of the reservoir to generate the production of carbon dioxide in situ; andsubsequently injecting a fluid into the core to complete recovery of oil from the reservoir, the fluid being selected from the group consisting of seawater, a solution of a high pH chelating agent, and a low salinity fluid.2. The method for enhanced oil recovery according to claim 1 , wherein the aqueous solution comprises an aqueous solution of HNa-ethylenediaminetetraacetic acid having a pH of about 4.5.3. The method for enhanced oil recovery according to claim 1 , wherein the aqueous solution comprises an aqueous solution of H-hydroxyethyl ethylenediamine triacetic acid having a pH of about 2.5.4. The method for enhanced oil recovery according to claim 1 , wherein the aqueous solution comprises an aqueous solution of HNaHEDTA having a pH of about 4.5. The method for enhanced oil recovery ...

Reduction of breakdown pressure by filter cake removal using thermochemicals

A method for the simultaneous removal of filter cake from a wellbore and fracturing of the wellbore using a mixture including a chelating agent and a thermochemical. The method including feeding a mixture into the wellbore, contacting the filter cake with the mixture, reacting the chelating agent and the thermochemical to produce heat and pressure, removing the filter cake from the wellbore, and creating microfractures in the wellbore using pressure produced from the reacting.

METHOD OF MAINTAINING OIL RESERVOIR PRESSURE

The method of maintaining oil reservoir pressure involves injecting seawater having a concentration of about 1 wt % of a polyamino carboxylic acid or salt thereof as a chelating agent into the water zone of an oil reservoir, which reduces the formation of scale, thereby maintaining oil reservoir pressure. The polyamino carboxylic acid may be ethylenediaminetetraacetic acid (EDTA), acid (HEDTA), or hydroxyethyliminodiacetic acid (HEIDA). When used in larger concentrations, e.g., between 5 to 10 wt %, flooding the core with seawater containing the polyamino carboxylic acids not only prevents scale formation, but also improves core permeability. Instead of seawater, low salinity water may be used for the latter purpose. 1. A method of maintaining oil reservoir pressure , comprising the step of injecting untreated seawater containing an effective amount of a polyamino carboxylic acid or salt thereof as a chelating agent into the water zone of an oil reservoir to prevent scaling caused by precipitation of sulfates.2. The method of maintaining oil reservoir pressure according to claim 1 , wherein said effective amount of a polyamino carboxylic acid or salt thereof comprises about 1 wt % ethylenediaminetetraacetic acid (EDTA) or salt thereof.3. The method of maintaining oil reservoir pressure according to claim 2 , wherein said solution of EDTA in untreated seawater has a pH of about 11.4. The method of maintaining oil reservoir pressure according to claim 1 , wherein said effective amount of a polyamino carboxylic acid or salt thereof comprises about 1 wt % hydroxyethyl ethylenediaminetriacetic acid (HEDTA) or salt thereof.5. The method of maintaining oil reservoir pressure according to claim 4 , wherein said solution of HEDTA in untreated seawater has a pH of about 11.6. The method of maintaining oil reservoir pressure according to claim 1 , wherein said effective amount of a polyamino carboxylic acid or salt thereof comprises about 5 wt % hydroxyethyliminodiacetic acid ...

PROCESS FOR CONVERTING CALCIUM BENTONITE TO SODIUM BENTONITE

Method of converting calcium bentonite to sodium bentonite that is suitable for use as drilling mud or a cement additive. After the addition of a calcium bentonite sample to a prepared soda ash solution at predetermined soda ash/bentonite weight ratios, the bentonite suspension is continuously heated and stirred for up to 24 h. The heating and stirring are crucial towards enhancing the sodium activation of the bentonite, as well as other rheological properties of the bentonite. 1: A method of converting calcium bentonite to sodium bentonite , comprising:mixing a calcium bentonite sample with a sodium carbonate aqueous solution to form a bentonite suspension comprising calcium bentonite, sodium carbonate, and water,wherein the sodium carbonate aqueous solution comprises no more than 1% by weight of sodium carbonate based on the total weight of the water in the sodium carbonate aqueous solution,wherein the ratio of the weight of the sodium carbonate present in the sodium carbonate aqueous solution to the total weight of the calcium bentonite sample mixed with the sodium carbonate aqueous solution is 1:7 to 1:23, andwherein after the mixing, a calcium bentonite concentration in the bentonite suspension is from 5 to 10 wt % based on a total weight of the water in the bentonite suspension; andheating and stirring the bentonite suspension at below 80° C. for 6-24 hours to form a sodium bentonite product comprising water, sodium bentonite and calcium carbonate.24-. (canceled)5: The method of claim 1 , wherein the sodium bentonite product formed by the heating and stirring has an apparent viscosity of at least 15 cP.6: The method of claim 1 , wherein the sodium bentonite product formed by the heating and stirring has a yield point of no more than 30 lb/100 ft.7: The method of claim 1 , wherein the sodium bentonite product formed by the heating and stirring has a Na/Ca molar ratio of at least 2.5.8: The method of claim 1 , wherein the sodium bentonite product formed by the ...

METHOD OF ACIDIZING A GEOLOGICAL FORMATION AND METHOD OF DETERMINING AN EFFECTIVENESS OF ACIDIZING

A method acidizing a geological formation, and a method of determining an effectiveness of the acidizing with NMR spectroscopy. Various embodiments, or combinations of embodiments, of the method of acidizing and the method of determining the effectiveness of the acidizing are provided. 1. A method of acidizing a geological formation surrounding a wellbore , comprising:recording a first NMR spectrum of a portion of the geological formation over a micro-pore relaxation range, a meso-pore relaxation range, and a macro-pore relaxation range;calculating a first interconnectivity number by dividing a micro-meso interconnectivity number to a meso-macro interconnectivity number, wherein the micro-meso interconnectivity number is a ratio of an intensity of the first NMR spectrum at a micro-meso diffusional coupling to a peak intensity of the first NMR spectrum in the micro-pore relaxation range or the meso-pore relaxation range, and the meso-macro interconnectivity number is a ratio of an intensity of the first NMR spectrum at a meso-macro diffusional coupling to a peak intensity of the first NMR spectrum in the meso-pore relaxation range or the macro-pore relaxation range;acidizing the geological formation by delivering a stimulation fluid to the portion of the geological formation, thereby forming an acidized geological formation;recording a second NMR spectrum of the acidized geological formation over the micro-pore relaxation range, the meso-pore relaxation range, and the macro-pore relaxation range;calculating a second interconnectivity number by dividing a micro-meso interconnectivity number to a meso-macro interconnectivity number, wherein the micro-meso interconnectivity number is a ratio of an intensity of the second NMR spectrum at a micro-meso diffusional coupling to a peak intensity of the second NMR spectrum in the micro-pore relaxation range or the meso-pore relaxation range, and the meso-macro interconnectivity number is a ratio of an intensity of the second ...

Voltage regulator module with cooling structure

A high-power Voltage Regulator Module (VRM) includes a housing having side walls, an upper opening, and a lower opening, a VRM circuit board oriented within the housing, a plane of the VRM circuit board oriented in parallel to at least one of the side walls of the housing, an upper Printed Circuit Board (PCB) coupled to the upper opening of the housing, a lower panel coupled to the lower opening of the housing, a coolant inlet port formed in the lower panel, and a coolant outlet port formed in the lower panel. The high power VRM may include a coolant inlet adapter coupled to the coolant inlet port and a coolant outlet adapter coupled to the coolant outlet port. The coolant inlet adapter and the coolant outlet adapter may provide support for the VRM.

SALTWATER-BASED FRACTURING FLUID

A fracturing fluid composition that includes a chelating agent, e.g. GLDA, and a polymeric additive comprising a copolymer of acrylamido-tert-butyl sulfonate and hydrolyzed polyacrylamide diluted in an aqueous base fluid, e.g. seawater, and a method of fracking a geological formation using the fracturing fluid composition. Various embodiments of the fracturing fluid composition and the method of fracking are also provided. 1. A fracturing fluid composition , comprising:an aqueous base fluid having a chloride ion content of at least 6,000 ppm;a chelating agent comprising glutamic diacetic acid;guar gum; anda polymeric additive comprising a copolymer of acrylamido-tert-butyl sulfonate and partially hydrolyzed polyacrylamide, wherein a weight percent of acrylamido-tert-butyl sulfonate in the copolymer is in the range of 5 to 20 wt %, and a weight percent of the partially hydrolyzed polyacrylamide in the copolymer is in the range of 80 to 95 wt %, each relative to the total weight of the copolymer.2. (canceled)3. The fracturing fluid composition of claim 1 , wherein the polymeric additive further comprises one or more of xanthan claim 1 , polyacrylamide claim 1 , and a copolymer of acrylamido-tert-butyl sulfonate and acrylamide.4. (canceled)5. The fracturing fluid composition of claim 1 , wherein the aqueous base fluid is seawater.6. The fracturing fluid composition of claim 1 , wherein the chelating agent is present in the fracturing fluid composition at a concentration of no more than 30 wt % claim 1 , relative to the total weight of the fracturing fluid composition.7. The fracturing fluid composition of claim 1 , wherein the polymeric additive is present in the fracturing fluid composition at a concentration of no more than 1 wt % claim 1 , relative to the total weight of the fracturing fluid composition.8. The fracturing fluid composition of claim 1 , which does not include claim 1 , other than the chelating agent and the polymeric additive claim 1 , additional ...

GLUTAMIC DIACETIC ACID-CONTAINING AQUEOUS FLUID COMPOSITION

A fracturing fluid composition that includes a chelating agent, e.g. GLDA, and a polymeric additive comprising a copolymer of acrylamido-tert-butyl sulfonate and hydrolyzed polyacrylamide diluted in an aqueous base fluid, e.g. seawater, and a method of fracking a geological formation using the fracturing fluid composition. Various embodiments of the fracturing fluid composition and the method of fracking are also provided. 1. A fracturing fluid composition , comprising:an aqueous base fluid;a chelating agent comprising glutamic diacetic acid in an amount of 5-20 wt %, wherein wt % is relative to the total weight of the fracturing fluid composition; anda polymeric additive comprising a copolymer of acrylamido-tert-butyl sulfonate and partially hydrolyzed polyacrylamide, in an amount of 0.45-1 wt %, wherein wt % is relative to the total weight of the fracturing fluid composition;wherein a weight percent of acrylamindo-tert-butyl sulfonate in the copolymer is in the range of 5 to 20 wt %, and a weight percent of the partially hydrolyzed polyacrylamide in the copolymer is in the range of 80 to 95 wt %, each relative to the total weight of the copolymer.24-. (canceled)5. The fracturing fluid composition of claim 1 , wherein the aqueous base fluid is seawater.67-. (canceled)8. The fracturing fluid composition of claim 1 , which does not include claim 1 , other than the chelating agent and the polymeric additive claim 1 , additional additives selected from the group consisting of an antiscalant claim 1 , a deflocculant claim 1 , a crosslinker claim 1 , a breaker claim 1 , a fluid loss additive claim 1 , a buffer claim 1 , an interfacial tension reducer claim 1 , and a biocide.9. The fracturing fluid composition of claim 1 , which has a plastic viscosity of 2 to 8 cP at a temperature of 280 to 320° F.10. The fracturing fluid composition of claim 1 , which has a yield point of 2 to 15 lb/100 ftat a temperature of 280 to 320° F.1120-. (canceled)21. The fracturing fluid ...

ELECTROMOTIVE MACHINE

A linear electromotive machine, for example a motor, generator and/or eddy-current brake is disclosed. The machine comprises a stator and a rotor, the rotor comprising a Halbach magnet array mounted on a fibre-reinforced polymer rotor frame. Also disclosed is a transportation system including such a machine and a method of manufacturing such a machine. 1. A linear electromotive machine comprising a stator and a rotor , the rotor comprising a Halbach magnet array mounted on a fibre-reinforced polymer rotor frame.2. A machine as claimed in wherein the rotor frame is a carbon-fibre-reinforced polymer frame.3. A machine as claimed in wherein the frame does not include magnetic material.4. A machine as claimed in wherein the Halbach magnet array is comprised of a first row of magnets and a second row of magnets spaced apart from the first row claim 1 , each row of magnets itself being a Halbach array having a strong field side and a weak field side.5. A machine as claimed in wherein the surfaces of the first and second rows from which strong field sides emanate face toward one another.6. A machine as claimed in wherein the machine is configured such that claim 4 , in use claim 4 , the stator passes between the first and second row of magnets.7. A machine as claimed in wherein the rotor frame comprises two walls extending parallel to each other.8. A machine as claimed in wherein the first row of magnets is located adjacent the distal end of one wall and the second set of magnets is located adjacent the distal end of the other wall.9. A machine as claimed in wherein the machine is configured such that claim 7 , in use claim 7 , the stator passes between the two walls.10. A machine as claimed in wherein the linear electromotive machine is an alternating current synchronous motor.11. A machine as claimed in wherein the linear electromotive machine is a polyphase machine claim 10 , for example a three phase machine.12. A machine as claimed in wherein the stator comprises a ...

ENVIRONMENTALLY FRIENDLY STIMULATION FLUIDS, PROCESSES TO CREATE WORMHOLES IN CARBONATE RESERVOIRS, AND PROCESSES TO REMOVE WELLBORE DAMAGE IN CARBONATE RESERVOIRS

The present invention includes processes to create wormholes in carbonate reservoirs by contacting a formation with a solution comprising glutamic acid N,N-diacetic acid (GLDA) and/or a salt thereof, methylglycine-N,N-diacetic acid (MGDA) and/or a salt thereof, or a combination thereof. The present invention also includes processes to remove wellbore damage in a carbonate reservoir by contacting a damaged zone of the carbonate reservoir with a solution comprising GLDA and/or a salt thereof, methylglycine-N,N-diacetic acid (MGDA) and/or a salt thereof, or a combination thereof. The present invention further includes solutions comprising a salt and further comprising GLDA and/or a salt thereof, methylglycine-N,N-diacetic acid (MGDA) and/or a salt thereof, or a combination thereof. 1. Process to create wormholes in a carbonate reservoir by contacting a formation with a solution comprising a wormhole-forming agent , said wormhole forming agent consisting essentially of a chelating agent selected from the group consisting of glutamic acid N ,N-diacetic acid (GLDA) and/or a salt thereof , methylglycine-N ,N-diacetic acid (MGDA) and/or a salt thereof , or a combination thereof.2. Process of claim 1 , wherein the solution is an aqueous solution of about 10 to about 30 wt % of GLDA and/or a salt thereof claim 1 , MGDA and/or a salt thereof claim 1 , or a combination thereof.3. Process of claim 1 , wherein the solution further comprises a salt other than a salt of either GLDA or MGDA.4. Process of claim 3 , wherein the salt other than a salt of either GLDA or MGDA comprises a chloride salt claim 3 , a formate salt claim 3 , a bromide salt claim 3 , or a combination thereof.5. Process of claim 1 , wherein the pH of the solution is about 3 to about 5.6. Process of claim 1 , wherein the injection rate of the solution is about 0.25 to about 5 barrels/min.7. Process to remove wellbore damage in a carbonate reservoir by contacting a damaged zone of the carbonate reservoir with a ...

Acinetobacter O-Oligosaccharyltransferases and Uses Thereof

The present application provides methods and uses of O-oligosaccharyltransferase (O-OTases) for generating vaccines. In particular, the present application provides a method of synthesizing a glycoprotein comprising glycosylation of pilin-like protein ComP using a PglLO-OTase. Uses of glycoproteins synthesized by glycosylating ComP using PglLO-OTase, particularly for the preparation of vaccines and the like, including a vaccine to , is also provided. 1. A method of synthesizing a glycoprotein comprising glycosylation of ComP using a PglLComP O-oligosaccharyltransferase.2. The method of claim 1 , wherein the ComP is optionally fused to a second protein claim 1 , an adjuvant or a carrier.3. The method of claim 1 , which is performed in Gram negative bacteria.4AcinetobacterE. coli.. The method of claim 3 , wherein the bacteria is or5. The method of claim 4 , wherein the glycosylation uses sugars derived from O-glycosylation claim 4 , N-glycan claim 4 , O-antigens claim 4 , or a capsular polysaccharide.6Streptococcus. The method of claim 5 , wherein the capsular polysaccharide is a capsule.7StreptococcusStreptococcus pneumoniae.. The method of claim 6 , wherein the is8Campylobacter.. The method of claim 5 , wherein the N-glycan is derived from9Campylobacter jejuni. The method of claim 8 , wherein the N-glycan is a N-heptasaccharide.10AcinetobacterA. baylyi, A. baumannii, A. nosocomialisA. calcoaceticus.. The method of claim 4 , wherein the is claim 4 , or11. An O-oligosaccharyltransferase for glycosylation of ComP.12. The O-oligosaccharyltransferase of claim 11 , wherein the glycosylation is recombinantly produced in Gram negative bacteria.13AcinetobacterE. coli.. The O-oligosaccharyltransferase of claim 12 , wherein the bacteria is or14. The O-oligosaccharyltransferase of claim 11 , wherein the glycosylation uses sugars derived from O-glycosylation claim 11 , N-glycan claim 11 , O-antigens claim 11 , or capsular polysaccharide.15Streptococcus.. The O- ...

Protocol Layer Coordination Of Wireless Energy Transfer Systems

A method for protocol layer coordination of wireless energy transfer systems includes defining, by a master Internet of Things Access Point (IoTA), a set of configuration parameters. The master IoTA is one of a plurality of IoTAs. Each IoTA includes a controller in communication with a Power Access Point (PAP), an intercommunication radio and a Radio Frequency Identification (RFID) transceiver. The PAP is configured to energize an RFID tag, the intercommunication radio is configured to communicate between the master IoTA and a slave IoTA, and the RFID transceiver is configured to communicate with the RFID tag. Both the master IoTA and the slave IoTA are configured with the set of configuration parameters, transmitted by the master IoTA. The slave IoTA transmits an RFID command in response to the slave IoTA receiving the RFID request, from the master IoTA.

Process and fluid to improve the permeability of sandstone formations using a chelating agent.

La presente invención se relaciona con un proceso para tratar una formación de piedra arenisca que comprende introducir un fluido que contiene ácido glutámico-ácido N, N-diacético (GLDA, por sus siglas en inglés) o una sal del mismo y que tiene un pH de entre 1 y 14 en la formación. La invención además se relaciona con un fluido y con un kit de partes convenientes para el uso en el proceso anterior, que contienen ácido glutámico ácido N, N-diacético (GLDA, por sus siglas en inglés) o una sal del mismo, un inhibidor de corrosión, un tensioactivo, y opcionalmente un solvente mutuo.

Environmentally friendly stimulation fluids, processes to create wormholes in carbonate reservoirs, and processes to remove wellbore damage in carbonate reservoirs

The present invention includes processes to create wormholes in carbonate reservoirs by contacting a formation with a solution comprising glutamic acid N,N-diacetic acid (GLDA) and/or a salt thereof, methylglycine-N,N-diacetic acid (MGDA) and/or a salt thereof, or a combination thereof. The present invention also includes processes to remove wellbore damage in a carbonate reservoir by contacting a damaged zone of the carbonate reservoir with a solution comprising GLDA and/or a salt thereof, methylglycine-N,N-diacetic acid (MGDA) and/or a salt thereof, or a combination thereof. The present invention further includes solutions comprising a salt and further comprising GLDA and/or a salt thereof, methylglycine-N,N-diacetic acid (MGDA) and/or a salt thereof, or a combination thereof.

Process and fluid to improve the permeability of sandstone formations using a chelating agent

THE PRESENT INVENTION RELATES TO A PROCESS FOR TREATING A SANDSTONE FORMATION COMPRISING INTRODUCING A FLUID CONTAINING GLUTAMIC ACID N,N-DIACETIC ACID OR A SALT THEREOF (GLDA) AND HAVING A PH OF BETWEEN 1 AND 14 INTO THE FORMATION. THE INVENTION IN ADDITION RELATES TO A FLUID AND A KIT OF PARTS SUITABLE FOR USE IN THE ABOVE PROCESS CONTAINING GLUTAMIC ACID N,N-DIACETIC ACID OR A SALT THEREOF (GLDA), A CORROSION INHIBITOR, A SURFACTANT, AND OPTIONALLY A MUTUAL SOLVENT.

Process to control iron in oil and gas applications using a chelating agent

The present invention relates to a process to control iron in a subterranean formation wherein a fluid containing glutamic acid N,N-diacetic acid or a salt thereof (GLDA) and/or methylglycine N,N-diacetic acid or a salt thereof (MGDA) is introduced into the formation at a temperature between 77 and 400°F (about 2 and 204°C). The invention also covers a process of treating a subterranean formation wherein simultaneously iron control takes place.

Fluid suitable for treatment of carbonate formations containing a chelating agent

The present invention covers a fluid and kit of parts suitable for treating carbonate formations containing glutamic acid ?,?-diacetic acid or a salt thereof (GLDA) and/or methylglycine ?,?-diacetic acid or a salt thereof (MGDA), a corrosion inhibitor, and a surfactant, and the use thereof.

Chelating fluid for enhanced oil recovery in carbonate reservoirs and method of using the same

The chelating fluid for enhanced oil recovery in carbonate reservoirs and the method of using the same utilizes a chelating fluid injected into a carbonate oil reservoir through a fluid injection system. The chelating fluid is a solution of a polyamino carboxylic acid chelating agent in brine, with the polyamino carboxylic acid chelating agent having a concentration of approximately 5.0 wt % of the solution, with the solution having a pH of approximately 11.0. The polyamino carboxylic acid chelating agent is preferably ethylenediaminetetraacetic acid (EDTA). The brine preferably has a relatively high salinity, with a sodium chloride concentration preferably on the order of approximately 18,300 ppm.

Synthesis of thiazole derivative as anticancer and anti-antibiotics resistant bacteria agent

A thiazole derivative compound includes a compound having the following structural formula: or a pharmaceutically acceptable salt thereof.

Fluid suitable for treatment of carbonate formations containing a chelating agent.

La presente invención abarca un fluido y un kit de partes convenientes para tratar las formaciones de carbonato que contienen ácido glutámico-ácido N, N-diacético (GLDA, por sus siglas en inglés) o una sal del mismo y/o ácido N,N-diacético de metilglicina (MGDA, por sus siglas en inglés) o una sal del mismo, un inhibidor de corrosión, y un tensioactivo, y el uso de los mismos.

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Acinetobacter o-oligosaccharyltransferases and uses thereof

The present application provides methods and uses of O-oligosaccharyltransferase (O-OTases) for generating vaccines. In particular, the present application provides a method of synthesizing a glycoprotein comprising glycosylation of pilin-like protein ComP using a Pg1LComP O-OTase. Uses of glycoproteins synthesized by glycosylating Com P using Pg1LComP O-OTase, particularly for the preparation of vaccines and the like, including a vaccine to Streptococcus, is also provided.

Fluid suitable for treatment of carbonate formations containing a chelating agent

The present invention covers a fluid and kit of parts suitable for treating carbonate formations containing glutamic acid Ν,Ν-diacetic acid or a salt thereof (GLDA) and/or methylglycine Ν,Ν-diacetic acid or a salt thereof (MGDA), a corrosion inhibitor, and a surfactant, and the use thereof.

Environmentally friendly stimulation fluids, processes to create wormholes in carbonate reservoirs, and processes to remove wellbore damage in carbonate reservoirs

Environmentally friendly stimulation fluids, processes to create wormholes in carbonate reservoirs, and processes to remove wellbore damage in carbonate reservoirs Abstract 5 The present invention includes processes to create wormholes in carbonate reservoirs by contacting a formation with a solution comprising glutamic acid N,N-diacetic acid (GLDA) and/or a salt thereof, methylglycine-N,N-diacetic acid (MGDA) and/or a salt thereof, or a combination thereof. The present invention also includes processes to remove wellbore damage in a carbonate reservoir by contacting a damaged zone of the 1o carbonate reservoir with a solution comprising GLDA and/or a salt thereof, methylglycine-N,N-diacetic acid (MGDA) and/or a salt thereof, or a combination thereof. The present invention further includes solutions comprising a salt and further comprising GLDA and/or a salt thereof, methylglycine-N,N-diacetic acid (MGDA) and/or a salt thereof, or a combination thereof.

Ammonium salts of chelating agents and their use in oil and gas field applications

The present invention relates to a process for treating a subterranean formation wherein a fluid containing an ammonium salt of glutamic acid Ν, Ν-diacetic acid (GLDA) or methylglycine Ν, Ν-diacetic acid (MGDA) is introduced into the formation. The invention also covers a fluid containing an ammonium salt of GLDA and/or MGDA and at least one component from the group of seawater, mutual solvents, anti-sludge agents, (water-wetting or emulsifying) surfactants, foaming agents, corrosion inhibitors, corrosion inhibitor intensifiers, viscosifiers, wetting agents, diverting agents, oxygen scavengers, carrier fluids, fluid loss additives, friction reducers, stabilizers, rheology modifiers, gelling agents, scale inhibitors, breakers, salts, brines, pH control additives, bactericides/biocides, particulates, crosslinkers, salt substitutes (such as tetramethyl ammonium chloride), relative permeability modifiers, sulfide scavengers, fibres, nanoparticles, and consolidating agents, and covers an ammonium salt of the formula M x (NH 4 ) y H z -GLDA or the formula M x (NH 4 ) y H z -MGDA, wherein M is an alkalimetal cation, x is at least 0.1, y is at least 0.1 and x+y+z = 4 for GLDA and x+y+z = 3 for MGDA.

Systems, methods, and compositions for reservoir stimulation treatment diversion using thermochemicals

Reservoir stimulation treatment diversion methods, systems, and compositions. One method includes identifying a reservoir requiring liquid stimulation treatment in a lesser-permeability portion of the reservoir. The method includes identifying a greater-permeability portion of the reservoir, the greater-permeability portion of the reservoir having a greater permeability than the lesser-permeability portion. The method also includes disposing a gas in the greater-permeability portion of the reservoir; injecting a liquid stimulation treatment into the reservoir, and allowing the gas in the greater-permeability portion of the reservoir to divert the liquid stimulation treatment into the lesser-permeability portion to stimulate fluid production from the lesser-permeability portion of the reservoir.

Fluid suitable for treatment of carbonate formations containing a chelating agent

The present invention covers a fluid and kit of parts suitable for treating carbonate formations containing glutamic acid ?,?-diacetic acid or a salt thereof (GLDA) and/or methylglycine ?,?-diacetic acid or a salt thereof (MGDA), a corrosion inhibitor, and a surfactant, and the use thereof.

acinetobacter o-oligosaccharyl transferases and uses thereof

a presente invenção refere-se a métodos e usos da o-oligossacaril-transferase (o-otases) para a geração de vacinas. em particular, o presente pedido apresenta um método de síntese de uma glicoproteína que compreende a glicosilação da proteína similar à pilina comp usando uma pg1lcomp o-otase. são também apresentados usos de glicoproteínas sintetizadas por comp glicosilante utilizando pg1lcomp o-otase, particularmente para a preparação de vacinas e similares, inclusive uma vacina para streptococcus. The present invention relates to methods and uses of o-oligosaccharyl transferase (o-otases) for the generation of vaccines. In particular, the present application discloses a method of synthesis of a glycoprotein which comprises glycosylation of the pilin-like protein comp using a pg1lcomp o-otase. Uses of glycoprotein synthesized glycoproteins utilizing pg1comp o-otase are also disclosed, particularly for the preparation of vaccines and the like, including a streptococcus vaccine.

Cold plate with integrated sliding pedestal and processing system including the same

A cold plate with an integrated sliding pedestal and a processing system including the same are provided. In one aspect, the processing system includes a printed circuit board (PCB), a first electronic component arranged over the PCB, and a thermal interface material (TIM) arranged over the first electronic component. The system includes at least one sliding pedestal arranged over the TIM. The sliding pedestal is configured to be spaced a variable distance from the PCB. The system also includes a cold plate arranged over the sliding pedestal and configured to provide a coolant to the sliding pedestal and to cool a second electronic component.

Cocktail smoker

Reduction of breakdown pressure by filter cake removal using thermochemicals

A method for the simultaneous removal of filter cake from a wellbore and fracturing of the wellbore using a mixture including a chelating agent and a thermochemical. The method including feeding a mixture into the wellbore, contacting the filter cake with the mixture, reacting the chelating agent and the thermochemical to produce heat and pressure, removing the filter cake from the wellbore, and creating microfractures in the wellbore using pressure produced from the reacting.

Fiber reinforced sandwich composite panels and methods of making

Fiber reinforced sandwich composite panels and methods for manufacturing are described. The fiber reinforced sandwich composite panels comprise a top layer, a bottom layer, a core layer, a continuous reinforcing yarn passing through the panel at a plurality of apertures and a continuous weft yarn interlocked with the reinforcing yarn.

Electronic assemblies with thermal interface structure

Electronic assemblies such as system on a wafer assemblies are disclosed. The assembly can include an electronic component that has a first side, a heat removing structure that is coupled to the first side of the electronic component, and a thermal interface structure that includes a thermal interface layer and an adhesion layer. The electronic component can be a system on a wafer (SoW). The thermal interface layer is positioned between the first side of the electronic component and the heat dissipation structure. The adhesion layer is positioned between the heat removing structure and the thermal interface layer. With the thermal interface structure, the electronic component and the heat removing structure can be attached together with relatively lower pressure.

Methods of electronic system assembly with thermal interface pad and related assemblies

Aspects of this disclosure relate to a method of assembly that includes thermally coupling two components. The method includes providing a thermal interface pad between the two components, such as an integrated circuit and a cooling solution. The thermal interface pad can have a star shape, and a pressure is applied to at least one of the two components. The pressure can cause the star shape thermal interface to expand into a rectangular shape. The expanded rectangular shape does not expand into keep out area positioned around an electronic component of the two components.

Fracturing fluid based on oilfield produced fluid

A composition for a fracturing fluid may include a chelating agent, a polymeric gelling agent, and a base fluid. The base fluid in the fracturing fluid composition may be a produced fluid having a hardness content of at least 7,000 ppm. Method for treating a hydrocarbon-bearing formation may include introducing a fracturing fluid in the hydrocarbon-bearing formation. The fracturing fluid contains a chelating agent, a polymeric gelling agent, and a base fluid. The base fluid may be a produced fluid that has a hardness content of at least 7,000 ppm. The fracturing fluid may have a viscosity of at least 200 cp at 150° F., 100 1/s shear rate, and 300 psia when tested using model 5550 HPHT rheometer. After contacting the hydrocarbon-bearing formation, the viscosity of the fracturing fluid may drop near a range of 1 cP to 5 cP.

Self-destructive barite filter cake in water-based and oil-based drilling fluids

Drilling fluid compositions may include a weighting agent, a nitrite-containing compound, and an ammonium-containing compound, where the nitrite-containing compound and the ammonium-containing compound may be encapsulated together in copolymer micro-particles forming encapsulated thermochemical compounds, and where at least one property selected from the group consisting of the density, the plastic viscosity, the yield point, the gel strength, and the pH, of the drilling fluid composition may be substantially similar to the at least one property of a comparable drilling fluid composition devoid of the encapsulated thermochemical compounds. Methods for reducing a filter cake from a wellbore surface in a subterranean formation are also provided. The methods may include introducing into the wellbore the drilling fluid compositions, allowing the drilling fluid composition to reach a temperature in the wellbore sufficient for the encapsulated thermochemical compounds to react, where the reaction of the encapsulated thermochemical compounds generates heat and nitrogen gas.

Heavy oil as fracturing fluid to increase hydraulic fracturing efficiency

Compositions, systems, and methods for hydraulically fracturing a hydrocarbon-bearing formation, a method including injecting into the hydrocarbon-bearing formation under increased pressure a heavy oil fracturing fluid; allowing the heavy oil fracturing fluid to remain in situ for a period of time suitable to create fractures in the hydrocarbon-bearing reservoir, the heavy oil fracturing fluid operable to undergo an at least about 70% viscosity decrease in situ; and flowing back the heavy oil fracturing fluid to the surface without damaging the hydrocarbon-bearing formation or reducing production of hydrocarbons from the hydrocarbon-bearing formation.

Methods for reducing condensation

A method for reducing condensate in a subsurface formation is disclosed. The method comprises introducing a first reactant and a second reactant into the subsurface formation. The first reactant and the second reactant produce an exothermic reaction that increases temperature and pressure in the subsurface formation to greater than a dew point of the condensate. Increasing the temperature and pressure in the subsurface formation to greater than the dew point of the condensate vaporizes, and thereby reduces, condensate in the subsurface formation.

Electronic assemblies with thermal interface structure

Electronic assemblies such as system on a wafer assemblies are disclosed. The assembly can include an electronic component that has a first side, a heat removing structure that is coupled to the first side of the electronic component, and a thermal interface structure that includes a thermal interface layer and an adhesion layer. The electronic component can be a system on a wafer (SoW). The thermal interface layer is positioned between the first side of the electronic component and the heat dissipation structure. The adhesion layer is positioned between the heat removing structure and the thermal interface layer. With the thermal interface structure, the electronic component and the heat removing structure can be attached together with relatively lower pressure.

Passive fluid flow controlling device and system

A cooling system is disclosed. The cooling system can include a flow path including a main path and a secondary path. The secondary path can have an inlet and an outlet. The inlet can be in fluid communication with a first portion of the main path and the outlet can be in fluid communication with a second portion of the main path. The cooling system can include a passive fluid flow controller. The passive fluid flow controller can be positioned in the main path between the first portion and the second portion. The passive fluid flow controller can adjust an amount of a coolant that is routed to the secondary path from the main path through the inlet of the secondary path. The passive fluid flow controller can impede a particle from entering the secondary path via the inlet of the secondary path.

Fiber reinforced sandwich composite panels and methods of making

Fiber reinforced sandwich composite panels and methods for manufacturing are described. The fiber reinforced sandwich composite panels comprise a top layer, a bottom layer, a core layer, a continuous reinforcing yam passing through the panel at a plurality of apertures and a continuous weft yam interlocked with the reinforcing yam.

Invention of opening bottles in an easy way, bottles are closed with cork or similar products of same function

The automatic vessel.

Methods for wellbore formation using thermochemicals

A method for stimulating a well includes mixing at least one thermochemical with fracturing fluid to create a fracturing fluid mixture, injecting the fracturing fluid mixture into the well, creating an exothermic reaction with the fracturing fluid mixture, generating a pressure pulse in the well from the exothermic reaction, and fracturing a formation around the well with pressure from the pressure pulse and a hydraulic pressure source.

Removal of water blockage in tight gas reservoir using thermochemical fluids

Methods, systems, and compositions for increasing hydrocarbon production from a wellbore where the wellbore or a nearby hydrocarbon reservoir is suffering from water blockage, one method including identifying water blockage in a rock sample of a formation via increased capillary pressure in the rock sample; formulating an exothermic reaction component to remove water blockage from a reservoir rock in situ via heat and pressure release, the reservoir rock type the same as the rock sample; injecting the exothermic reaction component into the wellbore; and allowing the exothermic reaction component to react to remove water blockage in situ to decrease capillary pressure of the reservoir rock without substantially changing porosity of the reservoir rock.

Array of compliant connectors for electronic assemblies

An array of compliant connectors for electronic assemblies is provided. In one aspect, a system includes an array of first electronic components and an array of second electronic components. Each of the second electronic components is paired with corresponding to one of the first electronic components. Each pair of the first and second electronic components is coupled via a plurality of compliant connectors.

Electronic assemblies with thermal interface structure

Electronic assemblies such as system on a wafer assemblies are disclosed. The assembly can include an electronic component that has a first side, a heat removing structure that is coupled to the first side of the electronic component, and a thermal interface structure that includes a thermal interface layer and an adhesion layer. The electronic component can be a system on a wafer (SoW). The thermal interface layer is positioned between the first side of the electronic component and the heat dissipation structure. The adhesion layer is positioned between the heat removing structure and the thermal interface layer. With the thermal interface structure, the electronic component and the heat removing structure can be attached together with relatively lower pressure.

Cold plate having opening and related systems

Electronic assemblies with a cold plate having an opening are provided. In one aspect, a system includes an array of electronic components, a control board, and a cold plate having a plurality of openings therethrough. The cold plate can be arranged between the array of electronic components and the control board. The cold plate can cool the array of electronic components. The system can also include a plurality of pass through connectors arranged in the openings in the cold plate and configured to connect the array of electronic components to the control board. The cold plate can also be used to cool the control board electronics and the connectors passing through.

Cold plate having opening and related systems

Electronic assemblies with a cold plate having an opening are provided. In one aspect, a system includes an array of electronic components, a control board, and a cold plate having a plurality of openings therethrough. The cold plate can be arranged between the array of electronic components and the control board. The cold plate can cool the array of electronic components. The system can also include a plurality of pass through connectors arranged in the openings in the cold plate and configured to connect the array of electronic components to the control board. The cold plate can also be used to cool the control board electronics and the connectors passing through.

Sandwiched multi-layer structure for cooling high power electronics

The systems, methods, and devices disclosed herein relate to sandwiched multi-layer structures for cooling electronics. In some embodiments, a computing assembly can include a first cooling system, a first electronics layer, a second cooling system, and a second electronics layer. The first cooling system can be disposed on top of and can be in thermal communication with the first electronics layer, the first electronics layer can be disposed on top of and can be in thermal communication with the second cooling system, and the second cooling system can be disposed on top of and can be in thermal communication with the second electronics layer. In some embodiments, at least one layer can use system on wafer packaging.

Safety escape system for occupants in a submerged car

Cold plate with integrated sliding pedestal and processing system including the same

A cold plate with an integrated sliding pedestal and a processing system including the same are provided. In one aspect, the processing system includes a printed circuit board (PCB), a first electronic component arranged over the PCB, and a thermal interface material (TIM) arranged over the first electronic component. The system includes at least one sliding pedestal arranged over the TIM. The sliding pedestal is configured to be spaced a variable distance from the PCB. The system also includes a cold plate arranged over the sliding pedestal and configured to provide a coolant to the sliding pedestal and to cool a second electronic component.

Self-destructive barite filter cake in water-based and oil-based drilling fluids

Drilling fluid compositions may include a weighting agent, a nitrite-containing compound, and an ammonium-containing compound, where the nitrite-containing compound and the ammonium-containing compound may be encapsulated together in copolymer micro-particles forming encapsulated thermochemical compounds, and where at least one property selected from the group consisting of the density, the plastic viscosity, the yield point, the gel strength, and the pH, of the drilling fluid composition may be substantially similar to the at least one property of a comparable drilling fluid composition devoid of the encapsulated thermochemical compounds. Methods for reducing a filter cake from a wellbore surface in a subterranean formation are also provided. The methods may include introducing into the wellbore the drilling fluid compositions, allowing the drilling fluid composition to reach a temperature in the wellbore sufficient for the encapsulated thermochemical compounds to react, where the reaction of the encapsulated thermochemical compounds generates heat and nitrogen gas.

[UNK]

Une centrale hydroelectrique privee pour chaque nouveau ou ancien edifice

Les eaux utilisées par les habitants des appartements d'un edifice ou autre, ainsi que les eaux de pluie du terrace de l'édifice “s'il y aura”, qui sont recueilli dans des canalizations pour l'acheminement vers les égouts, ils seront exploités avant , par une central hydroélectrique, pour fournir de l'éléctricité aux habitants de l'édifice.

Cold plate with integrated sliding pedestal and processing system including the same

A cold plate with an integrated sliding pedestal and a processing system including the same are provided. In one aspect, the processing system includes a printed circuit board (PCB), a first electronic component arranged over the PCB, and a thermal interface material (TIM) arranged over the first electronic component. The system includes at least one sliding pedestal arranged over the TIM. The sliding pedestal is configured to be spaced a variable distance from the PCB. The system also includes a cold plate arranged over the sliding pedestal and configured to provide a coolant to the sliding pedestal and to cool a second electronic component.

Array of compliant connectors for electronic assemblies

An array of compliant connectors for electronic assemblies is provided. In one aspect, a system includes an array of first electronic components and an array of second electronic components. Each of the second electronic components is paired with corresponding to one of the first electronic components. Each pair of the first and second electronic components is coupled via a plurality of compliant connectors.

Cold plate having opening and related systems

Electronic assemblies with a cold plate having an opening are provided. In one aspect. a system includes an array of electronic components. a control board. and a cold plate having a plurality of openings therethrough. The cold plate can be arranged between the array of electronic components and the control board. The cold plate can cool the array of electronic components. The system can also include a plurality of pass through connectors arranged in the openings in the cold plate and configured to connect the array of electronic components to the control board. The cold plate can also be used to cool the control board electronics and the connectors passing through.

Method of producing sodium bentonite

Method of converting calcium bentonite to sodium bentonite that is suitable for use as drilling mud or a cement additive. After the addition of a calcium bentonite sample to a prepared soda ash solution at predetermined soda ash/bentonite weight ratios, the bentonite suspension is continuously heated and stirred for up to 24 h. The heating and stirring are crucial towards enhancing the sodium activation of the bentonite, as well as other rheological properties of the bentonite.

Ammonium salts of chelating agents and their use in oil and gas field applications

The present invention relates to a process for treating a subterranean formation wherein a fluid containing an ammonium salt of glutamic acid N,N-diacetic acid (GLDA) or methylglycine N,N-diacetic acid (MGDA) is introduced into the formation. The invention also covers a fluid containing an ammonium salt of GLDA and/or MGDA and at least one component from the group of seawater, mutual solvents, anti-sludge agents, (water-wetting or emulsifying) surfactants, foaming agents, corrosion inhibitors corrosion inhibitor intensifiers, viscosifiers, wetting agents, diverting agents, oxygen scavengers, carrier fluids, fluid loss additives, friction reducers, stabilizers, rheology modifiers, gelling agents, scale inhibitors, breakers, salts, brines, pH control additives, bactericides/biocides, particulates, crosslinkers, salt substitutes (such as tetramethyl ammonium chloride), relative permeability modifiers, sulfide scavengers, fibres, nanoparticles, and consolidating agents, and covers an ammonium salt of the formula M x (NH 4 ) y H z -GLDA or the formula M x (NH 4 ) y H z -MGDA, wherein M is an alkalimetal cation, x is at least 0.1, y is at least 0.1 and x+y+z=4 for GLDA and x+y+z=3 for MGDA.