165 results about "Fluid saturation" patented technology

The invention discloses a rock nuclear magnetic resonance relaxation signal measuring device of formation rock matter property, which comprises the following parts: magnet, probe, preposition amplifier, power amplifier, nuclear magnetic resonance controller and control computer, wherein the nuclear magnetic resonance controller generates specific frequency and waveshape radio frequency actuation impulse, which is sent to the nuclear magnetic resonance probe in the magnet after magnified; the rock sample is set in the exciting probe, which generates nuclear magnetic resonance backward wave signal; the nuclear magnetic resonance probe receives the backward wave signal and sends to the nuclear magnetic resonance controller after magnified, which is sent to the computer finally. The invention can generate the parameter for usage directly, which can be applied in the oil field nuclear magnetic resonance well.

The invention relates to a computed tomography (CT) scanning heterogeneous model testing system. The system comprises a CT scanning system, a displacement system, an overburden pressure system, a pressure measurement system, a heterogeneous multilayer core clamp holder and a metering system, wherein the heterogeneous multilayer core clamp holder consists of a shell, a rubber cylinder, a core left plug, a core right plug, a left fixing sleeve, a right fixing sleeve, a left fastening sleeve, a right fastening sleeve and a fixed bracket; the core right plug is provided with a plurality of liquid outlets; each liquid outlet is respectively aligned with one layer of core model; and a strip liquid outlet sealing gasket is formed on the core right plug, which correspond to a seam between two adjacent layers of core models, so that liquid flow passing through each layer of core model flows out from the corresponding liquid outlet of each layer of core model, and thus, intraformational heterogeneous water displacing oil layered measurement is realized. By the CT scanning system, the real-time on-line monitoring of the on-way distribution of saturation of fluid on each layer section in a heterosphere is realized so as to observe the interlayer communication phenomenon.

A method for estimating fluid saturation in a formation penetrated by a wellbore from nuclear magnetic resonance measurements made at a plurality of lateral depths into the formation from the wellbore includes estimating a bound water volume, a total porosity and a free water volume at each of the lateral depths from the nuclear magnetic resonance measurements. A minimum water saturation is estimated at each lateral depth from the total porosity, the free water volume and the bound water volume at each lateral depth. A value of water saturation is estimated at each lateral depth from the minimum water saturation at each lateral depth. A relationship between lateral depth and water saturation is determined. Water saturation is estimated at a selected lateral depth greater than the greatest lateral depth of the nuclear magnetic resonance measurements.

A method for determining surface relaxivity of a rock formation in a wellbore includes using measurements of nuclear magnetic resonance properties of the rock formation made from within a wellbore penetrating the rock formations includes determining nuclear magnetic relaxation properties from the measurements of the nuclear magnetic resonance properties. A diffusion property of the rock formation is determined from the measurements of the nuclear magnetic resonance properties. The surface relaxivity of the rock formation is determined from the relaxation properties and the diffusion property. The surface relaxivity and other nuclear magnetic resonance properties are used to infer wettability and / or fluid saturation of the rock formations.

The invention provides a multi-scale rock physical charting method and device for detecting reservoir hydrocarbon. The method comprises the steps as follows: obtaining a reservoir rock matrix model and a reservoir rock framework model; acquiring a liquid-containing rock model according to the reservoir rock matrix model, the reservoir rock framework model and liquid parameters; obtaining a multi-scale initial reservoir rock physical chart according to the liquid-containing rock model; correcting the initial reservoir rock physical chart under a plurality of frequency bands according to the rock physical experimental data: correcting the initial reservoir rock physical chart under an acoustic logging frequency band based on the logging interpretation result; correcting the initial reservoir rock physical chart based on the seismic interpretation result; and outputting the final reservoir rock physical chart after the correction, so as to carry out inversion of a reservoir rock physical parameter. With the adoption of the method provided by the invention, the precision of the rock physical chart can be increased, and the quantitative inversion of the rock parameter and the saturation of the liquid can be realized.

Method for determining time-dependent changes [73] in the earth vertical and horizontal electrical resistivity and fluid saturations from offshore electromagnetic survey measurements. The method requires both online and offline data, which should include at least one electromagnetic field component sensitive at least predominantly to vertical resistivity and another component sensitive at least predominately to horizontal resistivity [62]. Using a horizontal electric dipole source, online Ez and offline Hz measurements are preferred. For a horizontal magnetic dipole source, online H2 and offline E2 data are preferred. Magnetotelluric data may be substituted for controlled source data sensitive at least predominantly to horizontal resistivity. Maxwell's equations are solved by forward modeling [64,65] or by inversion [66,67], using resistivity models of the subsurface that are either isotropic contrast, and [64,66] or anisotropic [65,67]. Fluid saturation is determined from the vertical and horizontal resistivities using empirical relations or rock physics models [70].

A method including analyzing seismic data relating to a producing hydrocarbon reservoir is disclosed. The seismic data includes first and second sets of seismic data obtained at different times. An interval composed substantially of hard rock is identified in the hydrocarbon reservoir. 4D seismic attributes for the region are calculated. Rock physics relationships are applied to seismic data related to the interval according to the permeability associated therewith. A fluid saturation change or a pressure change of the interval is inferred based on outputs of the first or second sets of rock physics relationships and the calculated 4D attributes for the interval. The inferred fluid saturation change or pressure change of the interval is outputted.

A borehole logging system for determining bulk density, porosity and formation gas / liquid fluid saturation of formation penetrated by a borehole. Measures of fast neutron radiation and inelastic scatter gamma radiation, induced by a pulsed neutron source, are combined with an iterative numerical solution of a two-group diffusion model to obtain the formation parameters of interest. Double-valued ambiguities in prior art measurements are removed by using the iterative solution of the inverted two-group diffusion model. The system requires two gamma ray detectors at different axial spacings from the source, and a single neutron detector axially spaced between the two gamma ray detectors. The system can be embodied as a wireline system or as a logging-while-drilling system.

The invention relates to a device for measuring the three-phase permeability of supercritical CO2 emulsion by a steady-state flow method. The device comprises a one-dimensional rock core model and a computed tomography (CT) scanner, wherein an inlet end of the one-dimensional rock core model is connected an emulsion generator and a crude oil injection device which are connected with each other in parallel; an inlet end of the emulsion generator is connected with a CO2 gas injection device and a surface active agent injection device which are connected with each other in parallel; an outlet end of the one-dimensional rock core model is connected with a gas source bottle and a liquid-containing narrow-mouth bottle which are connected with each other in parallel; a gas outlet pipe of the liquid-containing narrow-mouth bottle is sequentially connected with a drying pipe and a flow meter. According to the method for measuring the three-phase permeability of the supercritical CO2 emulsion, the three-phase fluid saturation of the supercritical CO2 emulsion is accurately obtained by a CT double-energy synchronous scanning method, and the relevant data measured by the experiment is substituted into a Darcy-Weisbach formula, so that the three-phase relative permeability of the supercritical CO2 emulsion under the different degrees of saturation can be obtained; the method is also used for measuring CO2 foam flooding two-phase permeability. The device and the method are small in limitation, are capable of reasonably approaching the experimental real value, and are simple in operation and accurate in measurement.

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.

Production based saturation models of subsurface reservoirs of interest are formed in a computer based on data from well logs, production data and core data. Data of these types obtained over a period of time are used to form 4-D actual or measured production based saturation models of a reservoir illustrative of fluid movement in the reservoir over time. Simulation models of fluid saturation of the reservoir are also formed for comparable times. Composite models of the production based saturation models and the simulation models are formed for analysts to evaluate accuracy of the simulation models of the reservoir taking into account production experience. The simulation models can then be adjusted for changes noted in the reservoir and based on how gas and water have actually moved within the reservoir over time.

The present invention relates to a constant gradient field nuclear magnetic resonance (NMR) rock sample analysis method and instrument. The method includes: in a constant gradient magnetic field, performing NMR measurement to acquire data; converting the measured NMR data into a two-dimensional NMR spectrum D-T2; performing measurement and inversion on a standard sample of a constant gradient field to obtain a standard sample two-dimensional NMR spectrum D-T2; measuring the sample to acquire a two-dimensional NMR spectrum D-T2 of a fluid in the sample; identifying fluid types according to the practically measured two-dimensional NMR spectrum D-T2; computing the fluid property and the petrophysical parameters according to the two-dimensional NMR spectrum D-T2 of the fluid in the sample; performing single slice scanning on the sample to acquire partial oil and water saturation; performing continuous slice scanning to obtain axial oil and water saturation distribution and movable fluid saturation distribution of the sample.

The invention relates to a non-homogenous core holder for CT (computed tomography) scanning. A rubber cylinder is arranged in a shell; a core left top and a core right top arranged in the rubber cylinder and push against two ends of a multi-layer core mold; a core containing chamber which accommodates the multi-layer core mold is defined by the inner wall of the rubber cylinder, the core left top and the core right top; a left fixed sleeve and a right fixed sleeve are respectively sleeved on the core left top and the core right top; an enclosed annular confining pressure space is defined by the outer wall of the rubber cylinder, the left fixed sleeve, the right fixed sleeve and the inner wall of the shell; the shell is provided with a confining pressure interface, a confining pressure exhaust hole and a confining pressure discharging hole; the core left top is internally provided with a liquid inlet and a core exhaust hole; and the core right top is internally provided with a middle-layer liquid outlet, an upper-layer liquid outlet and a lower-layer liquid outlet. The holder can detect the on-way distribution of fluid saturation in each layer section in a non-homogenous layer on line in real time, and also can observe fluid channeling among layers.

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.

The invention provides a method for determining the nuclear magnetic resonance T2 cutoff value and the fluid saturation of tight oil, and an apparatus thereof. The method comprises the following steps: determining the carbon content of a sample to be measured to generate a carbon content determination result; determining the lower limit value of the pore throat radius of the sample to be measured according to the carbon content determination result; and determining the corresponding T2 cutoff value according to the lower limit value of the pore throat radius and the core relaxation rate of the sample to be measured. The T2 cutoff value is calculated by using the lower limit value of the pore throat radius of the tight oil movable fluid of the practical sample in the above scheme, and the lower limit value of the pore throat radius of the tight oil movable fluid of the practical sample is determined by adopting a course to fine pore throat carbon content gradual approximation technology, so the T2 cutoff value obtained in the invention is true.

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 invention relates to a method for improving computed tomography (CT) measured fluid saturation precision. The method comprises the following steps of: a, performing CT scanning on a dry core sample inside and outside a core holder respectively to acquire CT values; b, performing CT scanning on a core of complete saturated brine inside and outside the core holder respectively to acquire CT values; c, making bound water by using the core in the holder, measuring the CT value of the core in a bound water state, and calculating the saturation of the bound water according to the water or liquid outlet volume after the bound water is made completely; d, performing CT scanning on brine for saturation, oil for experiments and peripheral air respectively to acquire CT values, wherein the CT value of the air is a constant value in any medium; e, calculating the CT value of the brine and the CT value of the oil in the core holder by using formulas III and V; and f, calculating the oily watersaturation in the displacement process by using the formula V according to the corrected brine and oil CT values acquired in the step e, wherein the relative error of the saturation is within 1 percent.

The invention provides a method for calibrating the saturation of a closed coring well, comprising: step 1, based on the analysis data of the surface porosity Φs and the overburden porosity Φr measured by the core samples of the closed coring well, establishing the cause of the saturation caused by the change of the rock pores and oil-water volume The correction formula for the change of oil content and water saturation of the measured sample; step 2, establish the formula for the change of oil content and water saturation loss of the measured sample caused by degassing and draining; The mathematical correction model of saturation loss due to the change of pore volume and oil-water volume and fluid saturation loss caused by depressurization and degassing and drainage can obtain the real oil and water saturation of the underground before measuring the saturation loss of core samples. The correction method for measuring oil and water saturation of core samples from closed coring wells realizes the accurate calculation of oil and water saturation of oil layers under formation conditions, and provides important basic parameters for reservoir engineering optimization research.

The invention discloses a method for evaluating a reservoir stratum with a nuclear magnetic resonance logging interpretation chart, relating to the technical field of evaluation of petroleum geology exploration geological logging interpretation. The method comprises the steps of: selecting two parameters such as an oil saturation So and a movable fluid saturation BVM; obtaining a parameter M1 with the formulation M1=BVM*So; building Phi-M1 interpretation chart; computing the movable oil saturation Smo parameter with the formulation Smo=BVM-Smw; obtaining a parameter M2 with the formulation M2=Smo*phi; building So-M2 interpretation chart; and visually evaluating the classification of the reservoir stratum liquid with the two interpretation charts. The method can solve the problem for evaluating whether the reservoir stratum can generate liquid and the character of the fluid, can solve the problem for evaluating the oil content of the reservoir stratum and the oil capacity, removes uncertain factors of interpretation parameters caused by factors such as block, stratum position and oil content character, and the like, and has universal applicability in oil-containing bed series of clastic rocks.

A method for designing an absorbent article. The steps of the method are generating a physical spatial map of saturation of a fluid within an absorbent in a physical test environment, generating a virtual spatial map of saturation of a fluid within an absorbent in a virtual test environment, identifying absorbent-fluid interaction properties for the absorbent such that the virtual spatial map of saturation approximates the physical spatial map of saturation, inputting the absorbent-fluid interaction properties into a virtual model of the absorbent article to produce a representation of at least one feature of the absorbent article, evaluating the virtual model of the absorbent article to determine the performance of the at least one feature of the absorbent article, modifying the design of the absorbent article in response to the performance of the at least one feature of the absorbent article determined from the virtual model of the absorbent article.

A method for determining fluid saturation in a formation at a plurality of radial depths near a wellbore, the method including: obtaining multi-frequency nuclear magnetic resonance (NMR) response data for the formation; and processing the data to determine simultaneously the fluid saturation at each radial depth. A computer program product is provided.

The invention provides a reservoir capillary pressure curve determinator under a high temperature and a pressure. The determinator comprises a ring pressure system, an injection system, a core clamping system, a semi-permeable baffle plate, a back pressure system, a measuring system, a data automatically collecting and processing system, and a thermostat which are connected through pipelines. A semi-permeable baffle plate method is adopted to measure capillary pressure curves under a stratum condition, and the basic rationale is that a principle of balance between an impressed pressure and the capillary pressure is used to measure the capillary pressure curves under the high temperature and the pressure. Core saturated wetting phase fluid displaces a wetting phase with a nonwetting phase under a certain displacement pressure. When the impressed pressure overcomes the capillary pressure of a certain capillary in the core, the wetting phase fluid in the capillary is discharged gradually, and the wetting phase fluid saturation in the core is reduced. Pressure is increased stepwise, accumulated discharged quantity of the wetting phase fluid when the wetting phase fluid is no longer discharged and an injection pressure are measured, and the capillary pressure curves can be solved.

The present invention is experiment and detection method of oil / water phase splitting seepage resistance gradient and belongs to the field of reservoir physics research. Based on generalized seepage description theory, the flow state of any one differential linear seepage section in non-linear seepage curve may be described with the linear equation the present invention gives. The present invention proposes method of detecting oil / water phase splitting seepage resistance gradient, and by means of the method, seepage resistance gradient for the fluid phase in some flow rate and in certain conditions may be determined. The method of the present invention has the features of being simple, fast and accurate.

The invention provides a seismic wave attenuation and speed dispersion prediction method in a complex heterogeneous reservoir medium and belongs to the hydrocarbon fossil energy exploration and development field. The method comprises the following steps of (1) according to lithology, a fluid containing property, a fluid saturation Sg of the heterogeneous reservoir medium, carrying out two-dimensional rock physical modeling on a reservoir rock unit; (2) implementing a conventional two-dimensional seismic wave propagation simulation numerical experiment on a physical modeling acquired from the step (1), through applying a single source, realizing propagation of an elastic wave in the reservoir medium, acquiring a stress field and a speed field of each time layer and calculating a strain field of any one point in a space; (3) when the conventional two-dimensional seismic wave propagation simulation numerical experiment is completed, recording time records of the stress field and the strain field; (4) based on a macro average principle, calculating an average stress and a strain field of an REV unit, wherein psi belongs to {tauxx, tauzz, epsilonxx and epsilonzz}.

The invention provides a three-phase relative permeability testing method based on CT (computed tomography) scanning, the method is applied to a three-phase relative permeability testing system based on CT scanning; the system comprises a CT scanner, a rock core holder, a confining pressure system, a filling system and a return pressure control system, wherein the filling system comprises an oil filling system, a water filling system and a gas filling system which are respectively connected with an inlet end of the rock core holder; the method comprises the following steps: an inlet pressure gauge (7) is arranged at the inlet of the rock core holder (6); an outlet pressure gauge (4) is arranged at the outlet of the rock core holder (6); a confining pressure interface of the rock core holder (6) is connected with the confining pressure system; and the outlet end of the rock core holder (6) is connected with the return pressure control system. The system and the method are used for carrying out CT scanning on a whole three-phase displacement process and acquiring the pressure of the inlet and the outlet throughout the whole process so as to obtain fluid saturation data of the whole process; and the system and the method are visual and accurate in result, simple in structure and convenient to operate.

The invention discloses a method for assessing a classification standard of a tight reservoir pore structure based on nuclear magnetic resonance. The method comprises the following steps of 1, measuring the porosity and permeability of each rock center; 2, measuring the displacement pressure, mid-value pressure, sorting coefficient, pore throat radius and maximum mercury saturability of each rockcenter; 3, analyzing the petrologic feature of each rock center, and the pore throat combination and pore type of the rock center; 4, testing the movable fluid saturation and the movable fluid porosity parameter of each rock center; and 5, based on the abovementioned parameters, dividing the rock centers into I, II and III three types according to the good, middle and bad comprehensive assessmentof reservoirs, and building a classification assessment standard of the three kinds of reservoirs. The invention firstly provides the method for assessing the classification standard of the tight reservoir pore structure based on nuclear magnetic resonance; the reservoir types divided by the method are more accurate and scientific, and the basis is provided for subsequent exploration and development of the tight reservoirs.

A method and apparatus for heat exchange with a volatile fluid in a parallel-channel capillary network traversing a solid receiver module manifests a multi-functional miniature device capable of performing as an evaporator, a condenser, a humidifier, a single-stream heat exchanger, a pressure generator, a thrust motor, a Fraunhofer diffraction device, or a collimation device. Heat is exchanged at a dedicated interface on the body by thermal contact or radiative fluence, and indirectly with the working fluid. Application-specific process control is manifested by applied heat rate, control of fluid saturation levels and vapor partial pressure at the capillary ends, and arrangement of flow network connections. The system operates in steady-state or transient modes, depending on the adapted functional mode and duty cycle. Specific materials and working fluids tolerate transient system performance levels of apparent heat rates exceeding 10 [MW / m3] and local fluid pressures exceeding 1 [GPa].