145 results about "Fluid type" patented technology

An apparatus and method for determining the density and fluid-type of a fluid flowing in a capillary tube, the velocity and viscosity of a blood sample flowing in a capillary tube, the erythrocyte sedimentation rate (ESR) of a blood sample after flow has been brought to an abrupt stop in a capillary tube, and/or the zeta sedimentation rate (ZSR) of a blood sample after flow has been brought to an abrupt stop in a capillary tube. These measurements are accomplished by directing a waveform pulse, such as an ultrasound pulse, at a pre-determined frequency transversely across the capillary tube and sample fluid, and by determining the flight of time of the pulse through the capillary tube and sample fluid and/or the Doppler shift of the echo signals reflecting off cells moving forwardly or transversely within a flowing, or stationary, blood sample.

A fluid identification device of long life for identification of a target fluid. The device uses at least two liquid type detection parts each of which is equipped with both of a temperature detector and a heating element, selects electrical conduction to any one of the heating elements, and identifies the target fluid based on a fluid temperature detection signal of the temperature detector in the fluid detection part not including the heating element whose electrical conduction has been selected and an output of the fluid type detection circuit.

The invention discloses a method for judging the fluid type of a reservoir through an acoustic porosity-neutron porosity differential, which relates to the technical field of oil and gas logging, geology and core test analysis. The method comprises the following steps: 1) accurately calculating shale content, rock compositions, acoustic porosity and neutron porosity of the reservoir through core data calibration logging and logging data environment correction; 2) excluding the influence of factors such as lithology, borehole diameter and mud invasion on an acoustic transit time and neutron data; and 3) establishing a standard for judging the fluid type of the reservoir by comparing the magnitude of the acoustic porosity and the neutron porosity and using the response difference of the acoustic transit time and the neutron data to the gas and formation water. In the method, non-fluid influence factors such as the lithology, borehole conditions, mud invasion and the like are excluded when the fluid type of the reservoir is judged, so the characteristics of the influence of different fluids on the acoustic transit time and the neutron data can be grasped truly, and the coincidence rate of judging the fluid type of the reservoir is improved from 70 percent currently to over 90 percent.

A system extrapolates and interpolates patient fluid intake or output parameter values and associated cumulative values over variable time intervals from a reduced set of stored fluid parameter values affecting fluid cumulative volume computation or rate of fluid intake or output computation. The extrapolation and interpolation function accomodates drip (continuing) fluid volumes as well as supplemental (non-continuing e.g., bolus) fluid volumes. A patient medical parameter data processing system provides patient medical parameter data for trend indicative display covering a time period comprising user selectable patient parameter acquisition time intervals. The system includes an acquisition processor for receiving data identifying, for a continuing infusion, rate of volume of fluid infusion into a patient, a fluid type identifier and a start time and start date of said continuing infusion. The received data also identifies for a non-continuing infusion, a total volume of fluid infusion, a fluid type identifier and a time and date of the non-continuing infusion. A data processor determines, from the received data, a cumulative total volume infusion of a particular fluid into a particular patient for a particular user selectable patient parameter acquisition time interval.

A method and a device are proposed for determining the type of fluid in a fluid mass in an object. X-ray attenuation data is supplied from one or a plurality of X-ray recordings of an object area including the fluid mass in the object, which were acquired with at least two different X-ray spectra or detector weightings. The X-ray attenuation data is used to determine values for effective atomic number and density for the fluid mass and average these to obtain a mean value for effective atomic number and density for the fluid mass. Comparison data is also supplied, which indicates fluctuation ranges for combinations of effective atomic number and density for different types of fluid. The mean values for effective atomic number and density of the fluid mass are compared with the comparison data to determine the fluctuation range and thereby the type of fluid, into which the two mean values fall. The method and associated device can be used to determine the type of fluid in a fluid mass in an object in a reliable and unambiguous manner.

The invention discloses a method for identifying a fluid type of a reservoir with a complicated pore structure by using conventional logging information and relates to the technical field of judgment of the fluid type according to logging information for oil-gas field exploration and development. The method comprises the steps of 1, distinguishing a gas layer from a non-gas layer according to a ratio of the neutron porosity to the acoustic porosity or the density porosity, wherein the non-gas layer comprises a dry layer, a gas-water layer and a water layer; 2, distinguishing an effective reservoir from an ineffective reservoir in the non-gas layer by a pore-full intersection method; and 3, based on the effective reservoir in the second step, comprehensively identifying the fluid type of the reservoir by a pore-power intersection method and gas logging. According to the method disclosed by the invention, the technical problem in evaluation of fluid type identification for a high-porosity dry layer, a middle-porosity dry layer, a high-resistance water layer and a high-resistance gas-water layer well which have high bound water characteristics under the condition that only conventional logging information is provided is effectively solved, and the difficulty in judgment of the reservoir type represented by the Majiagou formation is effectively solved.

The invention discloses a method for judging a fluid type of a reservoir by utilizing logging data of while-drilling drilling fluid, which comprises the following steps of: A, data collection, i.e., collecting performance parameters of the while-drilling drilling fluid of a target stratum, wherein the performance parameters comprise electrical conductivity, a temperature, drilling time and a hydrocarbon component of the drilling fluid; B, data processing; C, setting of a crossplot graph data track, i.e., for a plumb shaft, respectively combining an Sf data track and a Tf data track to form an S-T data track, combining the Sf data track and a DHf data track to form an S-DH data track and respectively making crossplots; D, judgment of the fluid type, i.e., using the S-T dat track for judging a dry layer (a micro gas-bearing bed) and an aqueous layer, using the S-DH data track for the plumb shaft to judge the gas-bearing bed or a gas reservoir and using a DO-DH data track for judging an oil-bearing formation or the gas-bearing bed. When the method is adopted, an explanation result of the method is objective and accurate, the coincidence rate of the explanation result and the oil testing conclusion is high, and the requirements on production and research can be met.

The invention discloses a reservoir layer evaluation method by utilizing nuclear magnetic resonance logging interpretation parameters, relating to the geology logging interpretation evaluation technology field of petroleum geological exploration; oil saturation So and mobile fluid saturation BVM parameters are chosen, a formula M1=BVM*So is utilized to obtain the M1 parameter which reflects the oil characteristics of the reservoir layer and the total energy; by utilizing the formula SMo=BVM-SMw, the mobile oil saturation SMo parameter is calculated, and then the formula M2=SMO*phi is utilized to obtain the M2 parameter which reflects the recoverable oil volume of the recoverable oil volume, and then the fluid type is determined according to the numeric range of the M1 and M2 values; by adopting the method, different oil grades of the reservoir layer can be effectively and quantitatively divided in a refining way, the undetermined factors of the interpretation parameters caused by block, horizon and oil-containing characteristics are eliminated, and the reservoir layer evaluation method has general applicability to a clastic rock oil-containing bed series.

A method of identifying inflow locations along a wellbore includes obtaining an acoustic signal from a sensor within the wellbore, determining a plurality of frequency domain features from the acoustic signal, and identifying, using a plurality of fluid flow models, a presence of at least one of a gas phase inflow, an aqueous phase inflow, or a hydrocarbon liquid phase inflow at one or more fluid flow locations. The acoustic signal includes acoustic samples across a portion of a depth of the wellbore, and the plurality of frequency domain features are obtained across a plurality of depth intervals within the portion of the depth of the wellbore. Each fluid flow model of the plurality of fluid inflow models uses one or more frequency domain features of the plurality of the frequency domain features, and at least two of the plurality of fluid flow models are different.

One embodiment of the present invention comprises a mass flow controller. The mass flow controller may comprise a pair of thermal sensing elements, a bridge circuit adapted to receive at least one first signal from the pair of thermal sensing elements and a differential amplifier adapted to (i) receive at least one bridge signal from the bridge circuit, and (ii) emit an output signal generally proportional to a flow rate of fluid passing through the mass flow controller. The mass flow controller is also comprised in one embodiment of a filter portion of a control module having one or more first filters comprising substantially permanent parameters adapted to provide a more accurate output signal for a baseline fluid upon a change in the flow rate and one or more second filters comprising variable parameters, with each of the one or more second filters being adapted to provide a more accurate output signal for non-baseline fluids upon a change in the flow rate.

A fluid dispenser is disclosed where a backoff distance is determined and implemented to prevent leakage while dispensing sequentially an accurate, precise amount of fluid substantially independent of the fluid remaining in a syringe-type dispenser. The fluid characteristics of the fluid, e.g. viscosity, surface tension, etc. affect the backoff distance that may be determined heuristically for fluid type, amount of fluid remaining in the syringe and amount to be dispensed. Once the fluid characteristics are known, the dispensing may be accomplished automatically with a processor loading new drive and backoff steps to a motor controller.

The invention discloses a method for identifying water logging grades of an oil reservoir by using a neural network analogue cross plot. In the method, the conventional cross plot technology is improved by a neural network algorithm, so nonlinear identification and quantitative analysis functions of the cross plot are realized, and a back propagation (BP) neural network algorithm is used and the method comprises the following steps of screening object characteristic parameters, selecting network structure parameters, training a neural network model, testing the network model, and establishing a neural network analogue cross plot layout. The method specifically comprises the following steps of: according to various characteristics of oil, gas and water layers in reservoirs, accurately selecting parameter samples which can best reflect the characteristics of the oil, gas and water layers in the reservoirs from parameters calculated during well logging or the well logging curves relevant to oil and gas interpretation by a statistics method; selecting appropriate weight values and threshold values by the BP neural network algorithm to establish the network model, and training the model and checking errors; and judging the fluid type or water logging degree of the reservoir with the depth according to projective points of identification vectors which are obtained by network output on a plane.

The invention relates to a crack fluid type identifying method based on longitudinal wave frequency depending on amplitude versus offset (AVO) and azimuth. Earthquake anisotropism is related to frequency, and when crack media are filled with different kinds of fluid, difference exists between anisotropism intensity and the earthquake frequency changing gradient. According to the method, frequency information is introduced into an AVO and azimuth inversion theory of elastic media, and the inversion theory is expanded to the field of viscoelasticity, namely AVO and azimuth depending on frequency. By solving the formula of the AVO and azimuth depending on frequency, a longitudinal wave anisotropism frequency dispersion item is obtained. The method has the advantages that the application effect of practical data shows that longitudinal wave anisotropism frequency dispersion can be used for identifying the type of fluid in a crack, meanwhile, the method is good in water identifying effect, and the method can be used for practical data and can identify the type of fluid in a crack on an area where the anisotropism degree is high.

In one embodiment, a method is provided for performing a fluid process within a machine having a fluid system including at least two reservoirs of different types of fluids. The method includes the steps of identifying a first reservoir for use in performing a fluid process; (a) adjusting a configuration of a valve system operatively coupled to the fluid system to permit a fluid evacuation process to be performed for the reservoir, (b) subsequently performing the fluid evacuation process for the reservoir, (c) subsequently adjusting the configuration of the valve system to permit a fluid refill process to be performed for the reservoir, (d) subsequently performing the fluid refill process for the reservoir; and, subsequently identifying an additional reservoir and performing at least one of the steps (a), (b), (c) and (d) for the additional reservoir, wherein the first reservoir includes a fluid of a type which is different from a type of a fluid of the additional reservoir. Various system and computer-readable media embodiments are also provided.

An ultrasound signal processor uses an excitation generator to cause displacement of a membrane or surface while a series of ultrasound pulses are applied to the membrane or surface. Phase differences between a transmitted signal and received signal are examined to determine the movement of the membrane or surface in response to the applied excitation. An examination of the phase response of the membrane or surface provides a determination as to whether the fluid type behind the membrane or surface is one of: no fluid, serum fluid, or purulent fluid.

The invention discloses a method and device for identifying a fluid type of a high-pressure fluid in a pipeline during rapid pressure change, belonging to the field of fluid type identification. The device mainly comprises an incoming fluid pipeline, a fixed baffle, an incoming fluid pipeline joint, an incoming fluid sensor three-way joint, a high-pressure resistant quartz transparent tube, an outgoing fluid sensor three-way joint, an outgoing fluid pipeline joint, an outgoing fluid pipeline, an adjusting sleeve, an adjusting bolt with a through hole, an incoming fluid pressure sensor, an incoming fluid pressure transmitter, an outgoing fluid pressure sensor, an outgoing fluid pressure transmitter, a computer, a light source and a high-speed video camera. The pipeline is sealed by adjusting the screwing length of the adjusting sleeve and the adjusting bolt with the through hole. The method comprises the steps of: performing Hilbert-Huang transformation on pressure differential data to obtain each modulus energy ratio; then regarding each modulus energy ratio as input vectors of an Elman neural network to finish mapping from a characteristic space to a fluid type space. The method and device for identifying the fluid type of the high-pressure fluid in the pipeline during the rapid pressure change, disclosed by the invention, has advantages of simple structure, convenience in detachment and capability of identifying fluid type of high-pressure fluid in the pipeline rapidly and exactly during the rapid pressure change.

The interior of a manifold (1) comprises, for each of a plurality of fluid types supplied to a fuel cell stack (2), an interior side passage (11b-13b) connected to a fluid supply/discharge port (2f) of the stack, and an exterior side passage (11a-13a) which connects the interior side passage to an external pipe. The interior side passage is formed in tiered fashion for each of the fluid types, and one or all of the exterior side passages and interior side passages communicate via a volume portion (11c-13c) which passes vertically through the interior of the manifold in the tier direction. By providing the volume portion, which has a large passage sectional area, resistance acting on the fluid that flows into the stack can be reduced, and as a result, energy loss can be suppressed.

More and more attentions are paid to the frequency dispersion phenomenon recently due to the fact that a great amount of information relating to fluid is carried. Even though the frequency dependence AVO inversion method is proved to be an effective method for judging fluid types, the reliability of the frequency dependence AVO inversion method relies on the accuracy degree of an AVO inversion approximation formula and the value of Vs/Vp in a frequency dispersion inversion formula to a great extent. Therefore, the invention provides a fluid identification method based on three-term frequency dependence AVO inversion. The method is based on an Aki&Richards three-term inversion approximation formula, and the Aki&Richards three-term inversion approximation formula is introduced to a frequency domain and is substituted into the Vs/Vp which is obtained through prestack AVO inversion and changes along with sampling points. According to the method, two-dimensional physical model data with holes filled with different fluids in sequence are selected and used firstly for verifying the feasibility and the advantages of the method, the result shows that more reliable longitudinal wave frequency dispersion gradient values can be obtained through the fluid identification method based on the three-term frequency dependence AVO inversion, and the fluid types can be identified more effectively and non-reservoir energy can be suppressed. The application results of actual data show that the final result obtained through the fluid identification method based on the three-term frequency dependence AVO inversion can be better matched with actual fluid types, yields and other well information.