93 results about "Water fraction" patented technology

A method and plant for the treatment of an organic waste material in liquid form, e.g. liquid manure from livestock, the method comprising filtering fibres and particles from the liquid, subjecting the liquid to anaerobic fermentation in a biogas reactor, separating a substantially sterile and particle-free permeate stream from the biogas reactor, e.g. using ultrafiltration, subjecting the permeate stream to treatment with an ammonia stripper at an elevated temperature and preferably at reduced pressure to remove substantially all ammonia and carbon dioxide and to result in an ammonia fraction and a nutrient salt fraction, and separating the nutrient salt fraction into a fertiliser concentrate fraction and a water fraction, e.g. using reverse osmosis. The end products of the method are clean water, ammonia concentrate, fertiliser concentrate containing salts of P and K, compost and high-quality biogas with a high methane content.

A method and system is disclosed for communicating information from a downhole location to the surface including a plurality of releasable vessels containing predetermined signal information affixed to the vessels prior to placement of the vessels downhole and indicative of the presence of at least one of three or more predetermined downhole conditions and a sensing and releasing system that senses the occurrence of the downhole condition, such as a simple threshold, and release the vessels in response to the sensing. The predetermined downhole condition can be characteristic of the fluid being produced in the borehole, such as water fraction, a certain level of mechanical wear or damage to downhole equipment such as bit wear, or the firing a one or more charges on a wireline deployed perforation tool.

In industrial sensing applications at least one parameter of at least one fluid in a pipe 12 is measured using a spatial array of acoustic pressure sensors 14,16,18 placed at predetermined axial locations x1, x2, x3 along the pipe 12. The pressure sensors 14,16,18 provide acoustic pressure signals P₁(t), P₂(t), P₃(t) on lines 20,22,24 which are provided to signal processing logic 60 which determines the speed of sound a_mix of the fluid (or mixture) in the pipe 12 using acoustic spatial array signal processing techniques with the direction of propagation of the acoustic signals along the longitudinal axis of the pipe 12. Numerous spatial array-processing techniques may be employed to determine the speed of sound a_mix. The speed of sound a_mix is provided to logic 48, which calculates the percent composition of the mixture, e.g., water fraction, or any other parameter of the mixture, or fluid, which is related to the sound speed a_mix. The logic 60 may also determine the Mach number Mx of the fluid. The acoustic pressure signals P₁(t), P₂(t), P₃(t) measured are lower frequency (and longer wavelength) signals than those used for ultrasonic flow meters, and thus is more tolerant to inhomogeneities in the flow. No external source is required and thus may operate using passive listening. The invention will work with arbitrary sensor spacing and with as few as two sensors if certain information is known about the acoustic properties of the system. The sensor may also be combined with an instrument, an opto-electronic converter and a controller in an industrial process control system.

A measurement device is provided that determines fluid properties from vibration frequencies of a sample cavity. In one embodiment, the measurement device includes a sample flow tube, vibration source and detector mounted on the tube, and a measurement module. The sample flow tube receives a flow of sample fluid for characterization. The measurement module employs the vibration sources to generate vibrations in the tube. The measurement module combines the signals from the vibration detector on the tube to determine properties of the sample fluid, such as density, viscosity, compressibility, water fraction, and bubble size. The measurement module may further detect certain flow patterns such as slug flow, for example. To measure the sample fluid density, the measurement module determines the resonant frequency of the sample flow tube. The density can then be calculated according to a formula that compensates for the temperature and pressure of the system.

A flowmeter, and a method of, measuring the flow of a multi-phase fluid is described. The flowmeter has a first pressure sensor located in a conduit for measuring a first pressure differential at a first location and a second response sensor spaced along the conduit for measuring a second pressure differential at a second location. The flowmeter includes pressure drop creation means for causing a drop in fluid pressure between the first and second locations, and a water fraction meter upstream of the first location or downstream of the second location for measuring the fraction of water in the multi-phase fluid. Various embodiments of the invention are described and in a preferred arrangement the first and second pressure measuring means are venturi flowmeters.

Multi-phase flow is estimated in a flow meter having a first and a second stage by empirically deriving an algorithm for the water and gas fractions, measuring pressures within the flow meter, and estimating a total mass flow rate based on the measured pressures. A corrected total mass flow rate is calculated using a liquid/gas slip correction technique. The oil fraction can be determined from the corrected total mass flow rate and gas and water fractions.

Disclosed is a process for the upgrading of heavy oils and bitumens, where the total feed to the process can include heavy oil or bitumen, water, and diluent. The process can include the steps of solvent deasphalting 110 the total feed 105 to recover an asphaltene fraction 116, a deasphalted oil fraction 118 essentially free of asphaltenes, a water fraction 112, and a solvent fraction 114. The process allows removal of salts from the heavy oils and bitumens either into the aqueous products or with the asphaltene product.

The vacuum thermal insulation material of the present invention comprises: a core material part which is hermetically sealed under reduced pressure; a getter part which is provided on one side in the middle of the core part; and an outer skin material part which surrounds the core material part and is hermetically sealed. In the getter part, a getter material, comprising a mixture of a hygroscopic material and a gas-adsorbing material, is packed in the form of a nonwoven fabric. In the vacuum thermal insulation material of the present invention, the hygroscopic material is any one of calcium oxide, calcium chloride, zeolite, silica gel, alumina and activated carbon, while the gas-adsorbing material is an oxygen-adsorbing material comprising a Fe based compound; and the hygroscopic material and the gas-adsorbing material are mixed in a ratio of between 20:1 and 200:1.

Provided is A method of manufacturing diesel fuel, including: fractionating in a first fractionator a synthetic oil obtained by Fisher-Tropsch synthesis into at least two fractions of a middle fraction, and a wax fraction containing a wax component heavier than the middle fraction; hydroisomerizing the middle fraction by bringing the middle fraction into contact with a hydroisomerizing catalyst to produce a hydroisomerized middle fraction; hydrocracking the wax fraction by bringing the wax fraction into contact with a hydrocracking catalyst to produce a wax decomposition compound; fractionating in a second fractionator a mixture of the hydroisomerized middle fraction and the hydrocracked wax fraction into at least two fractions including a kerosene fraction and a gas oil fraction; and mixing the at least two fractions at a predetermined blend ratio to produce a diesel fuel having a kinematic viscosity at 30° C. of 2.5 mm²/s or more and a pour point of −7.5° C. or less.

Real time determination of the presence of emulsion in a formation fluid is accomplished using an optical probe, preferably an attenuated total reflectance probe. The determination can then be used to appropriately increase, decrease or leave unchanged the use of demulsification additives or other means to control emulsion formation. The method is particularly useful for free water knock-out separations, where a plurality of probes can be used to distinguish the location and/or volume of emulsion, or “rag”, layer and thereby to facilitate decantation of relatively pure oil and water fractions. It can also be effectively used in pipelines, and can optionally determine the degree of emulsification and trends toward emulsification or demulsification.

An immersion probe is described that includes sensing elements that allow for hydrate inhibitor dosage to be more efficiently provided into gas and/or oil wells. The immersion probe allows for detection of first appearance of water in a multiphase flow in a well, measuring the amount of inhibitor in water within the well, determining an accurate water-cut, and measuring other property such as water salinity. Accordingly, with the known water-cut, salinity and the water flow rate inferred from the inhibitor injection flow rate and inhibitor-in-water fraction, a correct dosage of the inhibitor can be injected to the well in order to prevent hydrate formation, while reducing overdosing. Water flow rate may also be inferred from an independently measured liquid flow rate and the immersion-probe measured water cut.

With the disclosed device, some or all of the available oil tank vent gas in a production system can be utilized to augment the primary fuel gas needed by a heater treater unit to separate the gas, oil, and water fractions from raw natural gas extracted at the wellhead. Augmenting the primary fuel gas with vent gas reduces the demand for primary fuel gas, which thereby increases the amount of gas traversing a meter. The disclosed device also provides for an auxiliary burner unit that can directly address any available oil tank vent gas that is not utilized to augment fuel gas as waste gas. A method and apparatus for reducing the venting of raw natural gas emissions from an oil storage tank is described.

An apparatus and method to determine fractions of various phases in a multiphase fluid. The apparatus includes main body including an interior configured receive a multiphase fluid and an exterior. The apparatus senses fluid pressure of multiphase fluid received in the interior and senses a fluid temperature of the multiphase fluid. The apparatus transmits an ultrasonic wave into the fluid and detects the transmitted wave to determine its velocity and attenuation. The apparatus may adjust the determined velocity and attenuation based on the temperature and pressure of the fluid to compensate for a difference between the sensed temperature and pressure and a standard temperature and pressure. The apparatus determines a gas fraction, water fraction, and a non-water fluid fraction of the multiphase fluid based on the sensed fluid pressure, the sensed fluid temperature, and the velocity and attenuation of the ultrasonic wave in the multiphase fluid.

Methods are disclosed for calculating a fat fraction corrected for noise bias of one or more voxels of interest using a magnetic resonance imaging (MRI) system. A plurality of image data sets are obtained each corresponding to NMR k-space data acquired using a pulse sequence with an individual associated echo time t_n. A system of linear equations is formed relating image signal values to a desired decomposed calculated data vector having a component such as a water and fat combination having zero mean noise, or having a real fat component and a real water component. A fat fraction is calculated from at least one component of the decomposed calculated data vector. In another embodiment, the system of linear equations is normalized and can directly estimate a fat fraction or a water fraction having reduced noise bias.

This invention relates to a method and plant for combined electric energy and water production, where the method comprises feeding substantially pure oxygen and a hydrocarbon fuel in a stochiometric ratio to a combustor (5), combusting the oxygen and hydrocarbon feed for forming an exhaust gas at comparatively high temperature and pressure, passing the exhaust gas at high temperature and pressure to an expander (7) that runs an electric generator (8) and an exhaust gas compressor (9), passing the exhaust gass exiting the expander to an exhaust gas cooler (11) which cools the gas to a temperature above the steam condensation temperature, passing the exhaust gas exiting the exhaust gas cooler to the exhaust gas compressor for pressurising, and passing the pressurised exhaust gas to an exhaust gas condenser (14) where the exhaust gas is condensed and thus separated into a substantially pure water fraction and a gaseous CO.

Methods and apparatus for determining a viscosity of oil in a mixture are disclosed herein. An example method includes determining water fractions of a mixture flowing into a downhole tool and determining viscosities of the mixture. The mixture includes water and oil. The example method also includes determining a viscosity of the oil based on the water fractions and the viscosities.

A method for harvesting potable water and energy from waste that comprises the steps of collecting the waste, separating the waste into a water fraction, a solid fraction, and a gas fraction, sterilizing the water fraction, converting the solid fraction into an energy resource; and scrubbing the gas fraction.