241 results about "Bulk modulus" patented technology

This invention shows how to make and use a biodiesel-based fuel in diesel engines without incurring the NOx penalty. Embodiments primarily relate to an optimum range of bulk modulus of compressibility for biodiesel blends, which results in generating “NOx neutral” biodiesel blends or to formulate biodiesel blends with lower NOx emissions than conventional petroleum diesel fuel. These biodiesel blends preferably comprise synthetic paraffinic middle distillate derived from a hydrocarbon synthesis to generate synthetic environmentally-friendly diesel fuels.

Method for converting seismic data to obtain a subsurface model of, for example, bulk modulus or density. The gradient of an objective function is computed (103) using the seismic data (101) and a background subsurface medium model (102). The source and receiver illuminations are computed in the background model (104). The seismic resolution volume is computed using the velocities of the background model (105). The gradient is converted into the difference subsurface model parameters (106) using the source and receiver illumination, seismic resolution volume, and the background subsurface model. These same factors may be used to compensate seismic data migrated by reverse time migration, which can then be related to a subsurface bulk modulus model. For iterative inversion, the difference subsurface model parameters (106) are used as preconditioned gradients (107).

The invention relates to a method for evaluating the permeability of a reservoir layer according to the interval transit time and density inversed pore flat degree, comprising the following steps: collecting the characteristics and physical property parameters of rock; calculating the bulk modulus and shear modulus of saturated rock; calculating the bulk modulus and shear modulus of a rock substrate and the bulk modulus of fluid; setting the initial flat degree of the pores; calculating the change relation of the modulus ratio of a dry rock skeleton along with the porosity; calculating the bulk modulus and shear modulus of the dry rock skeleton; calculating the bulk modulus and shear modulus of fluid saturated rock; comparing the bulk modulus and shear modulus obtained through forward calculation with the bulk modulus and shear modulus actually measured, and calculating the error between the bulk modulus and shear modulus obtained through forward calculation and the bulk modulus and shear modulus actually measured; and modifying the set pore flat degree by adopting a nonlinear global optimizing algorithm, and using the pore flat degree for speed prediction, fluid substitution, inversion of porosity and saturated degree and logging parameter evaluation after accurate moduli of the dry rock skeleton are obtained.

The invention relates to a reservoir shear wave velocity prediction method based on rock physics. The method comprises the steps that (1) supposing that the bulk modulus, the shear modulus and the density of a destination interval mineral are unknown constants, the error between a longitudinal wave velocity and a measured longitudinal wave velocity is acquired according to equation modeling, and the error between the acquired density and the measured density is calculated; (2) according to the minimum error criterion, the bulk modulus, the shear modulus and the density of a mineral component are inverted through a genetic algorithm; (3) and the shear wave velocity is calculated. According to the step (1), supposing that the elastic modulus of each rock component is an unknown constant in a reservoir logging curve section, the objective function of the inversion of the logging curve can be defined that a superscript M represents a simulation longitudinal wave velocity, O represents a logging observation longitudinal wave velocity, and w Rho and w rho represent normalized weighted coefficients; and the objective function is a nonlinear function of the bulk modulus, the shear modulus and the density of each mineral component. The method can be applied to a sand shale reservoir, and carbonate rock and other complex reservoirs.

PCT No. PCT / CN96 / 00104 Sec. 371 Date Sep. 29, 1998 Sec. 102(e) Date Sep. 29, 1998 PCT Filed Nov. 20, 1996 PCT Pub. No. WO97 / 19370 PCT Pub. Date May 29, 1997The general object of the present invention is to provide a method for determining and displaying the relative changes of elastic moduli and that of density of geologic formations and for utilizing these relative changes and plottings for gas / oil exploration, especially for direct gas and light oil detection. The said relative changes of elastic moduli are the relative change of Lame constant DELTA lambda / ( lambda +2 mu ), the relative change of shear modulus DELTA mu / ( lambda +2 mu ) and / or DELTA mu / [ kappa +(4 / 3) mu ], the relative change of bulk modulus DELTA kappa / [ kappa +(4 / 3) mu ]; and the relative change of density is DELTA rho / rho .

The invention discloses a method for quantificationally predicting sandstone reservoir fluid saturation by combining a well and seism in geophysical prospecting for petroleum. The method comprises the following steps of: acquiring and processing seismic data and log data to obtain each parameter curve; respectively determining the relationships among the shale content, the porosity and an elastic parameter of the well; establishing prediction models of the shale content and the porosity; calculating a pore volume modulus and a dry rock volume modulus to establish a modulus prediction model; establishing an effective reservoir water saturation prediction model; performing prestack seismic inversion by utilizing prestack seismic trace gathers and the log data to obtain an inversion data volume of each elastic parameter; calculating the dry rock volume modulus to solve the pore volume modulus by the obtained elastic inversion volume; and solving the water saturation by using the pore volume modulus. In the method, prestack seismic data and the log data are fully utilized for quantificationally predicting reservoir saturation; and good geological effects on predicting oil and gas saturation are achieved.

The invention discloses a method for calculating formation pressure based on petrophysical parameters, and uses well measurement data of a velocity of a P-wave VP, a velocity of a shear wave VS, a density Rho and a porosity Phi of formation. The method comprises the following steps: deriving a ratio value between a bulk modulus Kdry of a dry rock and a bulk modulus Kma of a rock matrix material by using a Gassmann equation; calculating an effective bulk modulus Kma of a mineral component according to a V-G-H model, calculating a bulk modulus Kf of a pore fluid according to a Wood model to calculate an effective stress coefficient Alpha and an Skempton coefficient B; and estimating the formation pressure according to an effective stress between the Skempton coefficient B and a porous media, the effective stress coefficient Alpha and the Skempton coefficient B. The method is suitable for a mixed lithology and a single lithology, the formation pressure is estimated without relying on a conventional under compaction theory of a mudstone or a shale, so that the calculated formation pressure is more close to real formation pressure.

A method and apparatus for determining the operating health of a hydraulic system are provided. The method may include the steps of determining a plurality of operating parameters of the hydraulic system during operation of the hydraulic system, determining an estimated working condition value of the hydraulic system, modifying the estimated working condition value as a function of the operating parameters, and determining the operating health of the hydraulic system as a function of the working condition value. In one method, the working condition value may be indicative of an effective bulk modulus value of an operating fluid within at least part of the hydraulic system.

The invention provides a method for determining subsurface fluid by seismic data obtained from geophysical exploration. The method comprises the following steps: converting the seismic data into bulk modulus and density data of the effective subsurface media; acquiring elastic modulus of the effective media at a borehole of a work area according to longitudinal and transverse wave log data; calculating the elastic modulus and the fluid modulus of the media at the borehole, porosity log data and pore aspect ratio spectrum data, low frequency model of solid matrix elastic modulus and the elastic modulus data volume of a dry solid matrix, separating well side fluid bulk modulus from the effective media bulk modulus which is inverted by the seismic data, and calibrating with the moduli of the borehole and well side fluid, and calibrating the moduli of other non-well side fluid by a calibration operator to identify the subsurface fluid. The method makes full use of the amplitude, frequency and phase information to invert the elastic modulus of the effective media, which reduces multi-resolution, breaks though the spherical void restriction and laboratory measurement requirements, and easily achieves the fluid modulus separation, and the fluid identification is direct, the result of the fluid identification is reliable, and the fitness of the fluid identification and well drilling result is up to more than 90%.

The invention provides a method for predicting the transversal wave velocity of a carbonatite rock reservoir and relates to the technical field of geophysical exploration. The method comprises the following steps: determining the mineral component, the reservoir porosity as well as the fluid saturation of the reservoir; dividing the reservoir porosity into a rigid porosity, a fracture porosity and a clay porosity; obtaining the parameters of each mineral in the reservoir; calculating the bulk modulus Km and the shear modulus mum of a rock matrix through a Voigt-Reuss-Hill average model; calculating rhom; generating kfl and rhofl; generating the equivalent density rhodry of a rock dry skeleton; sequentially adding the porosities into the rock matrix through a DEM model, and calculating Kdry and mudry; carrying out fluid replacement on the rock dry skeleton through a low-frequency Gassmann equation so as to generate the density rho of a saturated fluid rock; calculating Ksat and musat; calculating the longitudinal wave speed (as shown in the description) and the transversal wave speed (as shown in the description) of the saturated fluid rock, inverting a virtual fracture porosity phi'f by a simulated annealing method according to a first relative error (as shown in the description) or a second relative error of rho and rhoo; replacing phif with phi'f, returning and calculating to generate the transversal wave speed V1 of the carbonatite rock reservoir.

Systems and methods which determine geologic properties using acoustic analysis are shown. Acoustic signals are collected during processing (e.g., crushing, shearing, striking, compressing, etc.) of geologic media, such as rock samples, for determining geologic properties according to embodiments. The acoustic signals collected may include frequency information, amplitude information, time information, etc. which may be utilized in determining geologic properties, such as geologic media properties (e.g., mineralogy, porosity, permeability, sealing capacity, fracability, compressive strength, compressibility, Poisson's Ratio, Youngs Modulus, Bulk Modulus, Shear Modulus), geologic structure properties (e.g., lithology, seal quality, reservoir quality), geologic acoustic properties (e.g., acoustic logging effectiveness, acoustic response, natural or harmonic frequencies, etc.). Embodiments may be used to provide determination of geologic properties from a variety of geologic media samples, such as cuttings, core samples, etc.

A system for estimating a quantity of parasitic leakage of a fluid from a fluid collection unit includes a pressure sensor and a control circuit. The pressure sensor is coupled to the fluid collection unit and configured to produce a pressure value indicative of the pressure of the fluid collection unit. The control circuit is operable to determine a change in pressure value of the fluid collection unit and estimate the quantity of parasitic leakage based on the change in pressure value. The control circuit may also be operable to determine a bulk modulus value of the fluid and estimate the quantity of parasitic leakage based on the change in pressure value and the bulk modulus value.

A highly reliable stack type semiconductor package, which does not have a problem of interconnection areas becoming disconnected due to thermal expansion. The semiconductor package includes a second die adhesive, which is formed between a first semiconductor chip and a second semiconductor chip, applied to the upper surface of the first semiconductor chip, and extends to the wire forming units. The second die adhesive is selected to have a bulk modulus greater than 1 GPa to prevent electric disconnection due to breakage of wires in the stack type semiconductor package during thermal stress.

A system for estimating a quantity of parasitic leakage of a fluid from a fluid collection unit includes a pressure sensor and a control circuit. The pressure sensor is coupled to the fluid collection unit and configured to produce a pressure value indicative of the pressure of the fluid collection unit. The control circuit is operable to determine a change in pressure value of the fluid collection unit and estimate the quantity of parasitic leakage based on the change in pressure value. The control circuit may also be operable to determine a bulk modulus value of the fluid and estimate the quantity of parasitic leakage based on the change in pressure value and the bulk modulus value.

Method for converting seismic data to obtain a subsurface model of, for example, bulk modulus or density. The gradient of an objective function is computed (103) using the seismic data (101) and a background subsurface medium model (102). The source and receiver illuminations are computed in the background model (104). The seismic resolution volume is computed using the velocities of the background model (105). The gradient is converted into the difference subsurface model parameters (106) using the source and receiver illumination, seismic resolution volume, and the background subsurface model. These same factors may be used to compensate seismic data migrated by reverse time migration, which can then be related to a subsurface bulk modulus model. For iterative inversion, the difference subsurface model parameters (106) are used as preconditioned gradients (107).

An ECU calculates the difference between the fuel pressure in a high-pressure distribution pipe and a target pressure when fuel is injected only from an air-intake passage injector. The ECU determines the bulk modulus of fuel that is associated with the coolant temperature. The ECU determines the amount of fuel that is to be discharged from a high-pressure pump based on the pressure difference and the bulk modulus. Then, the ECU actuates the high-pressure pump in accordance with the determined discharge amount.

A method is provided for efficiently characterizing rock traversed while drilling a borehole for hydrocarbon reservoir development. A rock sample can be obtained having a provenance of collection linked to a specific region of the borehole, which is scanned to obtain a 2D digital image that is segmented to pixels characterized as pore space and as mineral matrix and defining a boundary between them. A transform relationship, for example, a form of the Kozeny-Carman equation adapted for application to a 2D segmented image environment, can be applied to calculate the estimated value for a target rock property, which can be absolute permeability, relative permeability, formation factor, elasticity, bulk modulus, shear modulus, compressional velocity, shear velocity, electrical resistivity, or capillary pressure, and the estimated value is used to characterize the rock at that region of the borehole. This affords an opportunity to quickly and efficiently develop massive data directly characterizing extended regions of rock, whether traversed by the borehole in this or a related well. Computerized systems, computer readable media, and programs for performing the methods are also provided.

The invention relates to a method for predicting three-dimensional abnormal pore pressure based on rock physical seismic information. The method comprises the steps that the lithologic stratum matrix bulk modulus is calculated by applying parameters of the rock physical longitudinal wave velocity, transverse wave velocity and density, rock core geological analysis is additionally conducted so as to calculate the dry pore spatial rigidity, the pore pressure coefficient is obtained accordingly, and the single-well stratum abnormal pore pressure is calculated; and secondly, a three-dimensional data cube of the longitudinal wave impedance, the transverse wave impedance, Poisson ratio and the density is obtained by applying a three-dimensional seismic reflection data cube and three-dimensional prestack elastic wave impedance retrieval method, and the three-dimensional stratum abnormal pore pressure is predicted by reference to the single-well stratum abnormal pore pressure calculation method and an obtained empirical formula. According to the method for predicting the three-dimensional abnormal pore pressure based on the rock physical seismic information, rock physical parameters obtained indirectly through logging and seismic geophysical methods are applied to prediction of the abnormal stratum pore pressure, and the practice is easier compared with direct measuring of rock physical parameters in a laboratory, more scientific compared with subjective parameter presetting, and finer compared with calculation separately through post-stack seismic velocity.

A method for estimating at least one elastic-wave-related property of a porous material from a sample thereof includes making a three dimensional tomographic image of the sample of the material. The image is segmented into pixels each representing pore space or rock grain. Bulk modulus and shear modulus of the porous material are determined from the segmented image at a frequency corresponding to mobile fluid. Bulk modulus and shear modulus of the porous material are determined from the segmented image at a frequency corresponding to immobile fluid. The at least one elastic-wave-related property is determined from the mobile fluid and immobile fluid moduli. The method includes at least one of storing and displaying the at least one elastic-wave-related property so determined.

Various semiconductor chip underfills and methods of making the same are provided. In one aspect, a method of manufacturing is provided that includes coupling a semiconductor chip to a substrate to leave a gap therebetween, and forming an underfill layer in the gap. The underfill layer includes a first plurality of filler particles that have a first average size and a second plurality of filler particles that have a second average size smaller than the first average size such that the first plurality of filler particles is concentrated proximate the substrate and the second plurality of filler particles is concentrated proximate the semiconductor chip so that a bulk modulus of the underfill layer is larger proximate the substrate than proximate the semiconductor chip.

The invention discloses a method for predicting the volume content of corrosion pores in a carbonate reservoir. The method comprises the following steps: step 1, obtaining physical parameters of the carbonate reservoir; step 2, based on the physical parameters obtained in the step 1, calculating the bulk modulus and shear modulus of saturated rock of an actually-measured carbonate reservoir; step 3, calculating the bulk modulus and shear modulus of a rock matrix of the carbonate reservoir and the bulk modulus of a pore fluid; step 4, establishing a dual-pore-medium critical porosity model, and calculating the bulk modulus and shear modulus of a rock framework of the carbonate reservoir; step 5, calculating the bulk modulus and shear modulus of saturated rock of the carbonate reservoir through a Geissmann equation; step 6, comparing the bulk modulus and shear modulus of saturated rock of the carbonate reservoir with the bulk modulus and shear modulus of saturated rock of the actually-measured carbonate reservoir, and calculating an error; and step 7, modifying the set volume content of corrosion pores, performing the step 4 to the step 6 in sequence, calculating an error corresponding to the set corrosion pore condition, and obtaining an optimal volume content of corrosion pores.

A system and method for modeling fluid effects in a subsurface reservoir combines high quality shear modulus data from modern sonic logs with the inherent stability of VpVs ratio to derive more credible dry frame bulk modulus, in turn leading to improved fluid saturation modeling and improve fluid effect modeling. The system and model are designed primarily for low porosity and mixed lithology subsurface reservoirs although they may also be used with confidence in high porosity reservoirs.

The present invention relates to a polishing pad which is characterized in that it has a polishing layer of rubber A-type microhardness at least 80 DEG and a cushioning layer of bulk modulus at least 40 MPa and tensile modulus in the range 0.1 MPa to 20 MPa, and to a polishing device which is characterized in that a semiconductor substrate is fixed to the polishing head, and an aforesaid polishing pad is fixed to the polishing platen so that the polishing layer faces the semiconductor substrate, and by rotating the aforesaid polishing head or the polishing platen, or both, the semiconductor substrate is polished. With the polishing device or polishing pad of the present invention for use in the mechanical planarizing process wherein the surface of the insulating layers or metal interconnects formed on a semiconductor substrate are smoothened, it is possible to uniformly planarize the entire semiconductor face and perform uniform polishing close up to the wafer edge and, furthermore, it is possible to provide a technique for achieving both uniformity and planarity under conditions of high platen rotation rate.

A tunable optical filter has a large diameter cane waveguide with “side-holes” in the cane cross-section that reduce the force required to compress the large diameter optical waveguide without overly compromising the buckling strength thereof. The large diameter optical waveguide has a cross-section of at least about 0.3 millimeters, including at least one inner core, a Bragg grating arranged therein, a cladding surrounding the inner core, and a structural configuration for providing a reduced bulk modulus of compressibility and maintaining the anti-buckling strength of the large diameter optical waveguide. The structural configuration reduces the cross-sectional area of the large diameter optical waveguide. These side holes reduce the amount of glass that needs to be compressed, but retains the large diameter.

The invention discloses an abnormal formation pressure calculation method. The method includes: acquiring first effective stress through the relation between Young modulus and longitudinal and transverse wave velocity; acquiring second effective stress through the relation between bulk modulus and the longitudinal and transverse velocity; subjecting the first effective stress and the second effective stress to weighted average to acquire a final effective stress result; according to the final effective stress result, determining abnormal formation pressure sections by the aid of the effective stress theory. With the method, precision in predicting formation pressure is improved, influence of containing gas in the formation on formation velocity is eliminated, a high-precision model is established between the formation velocity and the effective stress, and an elastic modulus weighing method is developed to have the formation pressure predicated.

A method is provided for efficiently characterizing rock traversed while drilling a borehole for hydrocarbon reservoir development. A rock sample can be obtained having a provenance of collection linked to a specific region of the borehole, which is scanned to obtain a 2D digital image that is segmented to pixels characterized as pore space and as mineral matrix and defining a boundary between them. A transform relationship, for example, a form of the Kozeny-Carman equation adapted for application to a 2D segmented image environment, can be applied to calculate the estimated value for a target rock property, which can be absolute permeability, relative permeability, formation factor, elasticity, bulk modulus, shear modulus, compressional velocity, shear velocity, electrical resistivity, or capillary pressure, and the estimated value is used to characterize the rock at that region of the borehole. This affords an opportunity to quickly and efficiently develop massive data directly characterizing extended regions of rock, whether traversed by the borehole in this or a related well. Computerized systems, computer readable media, and programs for performing the methods are also provided.

The invention discloses an oil liquid elastic modulus tester based on bulk modulus definition. The cylinder rod of the loading cylinder inserts into the test channel to do axial displacement; the oil inlet port of the single direction value is connected with the rod channel of the loading cylinder and the oil outlet port is connected with the test channel; the pressure sensor is connected with the test channel; the built-in type displacement sensor is positioned in the punch and the cylinder rod; the non-rod channel and the rod channel of the loading cylinder and the test channel are separately connected with the liquid pressure system. It uses the loading cylinder to press the oil liquid of the test channel and changes the pressure to obtain the corresponding changing value of the oil liquid volume.

Especially, the invention is related to method for exploring petroleum. The direct carbon hydrogen detection factor utilized is Lame's constant reflectivity, shear modulus reflectivity, compressive bulk modulus reflectivity, difference between Lame's constant reflectivity and shear modulus reflectivity, and summation of Lame's constant reflectivity and shear modulus reflectivity. When the method determines the direct carbon hydrogen detection factor, approximate formula of longitudinal wave reflection coefficient in Zeoppritz combined equations utilized in the method is first approximate formula and second approximate formula.

The present invention provides a gas oil composition for use in a diesel engine with a geometric compression ratio of 16 or less, equipped with a supercharger and an EGR, containing an FT synthetic base oil and having a sulfur content of 5 ppm by mass or less, an oxygen content of 100 ppm by mass or less, a bulk modulus of 1250 MPa or greater and 1450 MPa or less, a saybolt color of +22 or greater, a lubricity of 400 μm or less, an initial boiling point of 140° C. or higher and an end point of 380° C. or lower in distillation characteristics, and the following characteristics (1) to (3) in each fraction range wherein: (1) the cetane number in a fraction range of lower than 200° C. is 40 or greater and less than 60; (2) the cetane number in a fraction range of 200° C. or higher and lower than 280° C. is 60 or greater and less than 80; and (3) the cetane number in a fraction range of 280° C. or higher is 50 or greater. The gas oil composition is used in a summer or winter season, suitable for both diesel combustion and homogeneous charge compression ignition combustion.